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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

 

(Mark One)

☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2021

or

☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from             to            

Commission File Number 001-35410

Matador Resources Company

(Exact name of registrant as specified in its charter)

Texas

27-4662601

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

5400 LBJ Freeway,

Suite 1500

75240

Dallas,

Texas

(Address of principal executive offices)

(Zip Code)

(972) 371-5200

(Registrant’s telephone number, including area code)

_________________________________________________________  

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading symbol(s)

Name of each exchange on which registered

Common Stock, par value $0.01 per share

MTDR

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes  ☒ No  ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes  ☐    No  ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   

Yes  ☐    No  ☒

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $3,979,787,498.

As of February 22, 2022, there were 118,043,776 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2022 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates.

Auditor Name: KPMG LLP			Auditor Location: Dallas, TX			Auditor Firm ID: 185

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Table of Contents

MATADOR RESOURCES COMPANY

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2021

TABLE OF CONTENTS

 

						Page
PART I
ITEM 1.			Business			2
ITEM 1A.			Risk Factors			34
ITEM 1B.			Unresolved Staff Comments			64
ITEM 2.			Properties			65
ITEM 3.			Legal Proceedings			65
ITEM 4.			Mine Safety Disclosures			65
PART II
ITEM 5.			Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			66
ITEM 6.			Selected Financial Data			69
ITEM 7.			Management’s Discussion and Analysis of Financial Condition and Results of Operations			69
ITEM 7A.			Quantitative and Qualitative Disclosures about Market Risk			88
ITEM 8.			Financial Statements and Supplementary Data			90
ITEM 9.			Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			90
ITEM 9A.			Controls and Procedures			90
ITEM 9B.			Other Information			93
PART III
ITEM 10.			Directors, Executive Officers and Corporate Governance			93
ITEM 11.			Executive Compensation			93
ITEM 12.			Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			93
ITEM 13.			Certain Relationships and Related Transactions, and Director Independence			93
ITEM 14.			Principal Accounting Fees and Services			93
PART IV
ITEM 15.			Exhibits and Financial Statement Schedules			94
ITEM 16.			Form 10-K Summary			94

 

i

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; our ability to replace reserves and efficiently develop current reserves; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; impact on our operations due to seismic events; availability of sufficient capital to execute our business plan, including from future cash flows, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; weather and environmental conditions; the impact of the worldwide spread of the novel coronavirus (“COVID-19”) on oil and natural gas demand, oil and natural gas prices and our business; the operating results of our midstream joint venture’s oil, natural gas and water gathering and transportation systems, pipelines and facilities, the acquiring of third-party business and the drilling of any additional salt water disposal wells; and the other factors discussed below and elsewhere in this Annual Report and in other documents that we file with or furnish to the United States Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about:

•our business strategy;

•our estimated future reserves and the present value thereof, including whether or not a full-cost ceiling impairment could be realized;

•our cash flows and liquidity;

•the amount, timing and payment of dividends, if any;

•our financial strategy, budget, projections and operating results;

•the supply and demand of oil, natural gas and natural gas liquids;

•oil, natural gas and natural gas liquids prices, including our realized prices thereof;

•the timing and amount of future production of oil and natural gas;

•the availability of drilling and production equipment;

•the availability of oil storage capacity;

•the availability of oil field labor;

•the amount, nature and timing of capital expenditures, including future exploration and development costs;

•the availability and terms of capital;

•our drilling of wells;

•our ability to negotiate and consummate acquisition and divestiture opportunities;

•the integration of acquisitions with our business;

•government regulation and taxation of the oil and natural gas industry;

•our marketing of oil and natural gas;

•our exploitation projects or property acquisitions;

•our ability and the ability of our midstream joint venture to construct, maintain and operate midstream pipelines and facilities, including the operation of its Black River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells;

•the ability of our midstream joint venture to attract third-party volumes;

•our costs of exploiting and developing our properties and conducting other operations;

•general economic conditions;

•competition in the oil and natural gas industry, including in both the exploration and production and midstream segments;

•the effectiveness of our risk management and hedging activities;

•our technology;

•environmental liabilities;

•our initiatives and efforts relating to environmental, social and governance matters;

•counterparty credit risk;

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•geopolitical instability and developments in oil-producing and natural gas-producing countries;

•the impact of COVID-19 on the oil and natural gas industry and our business;

•our future operating results; and

•our plans, objectives, expectations and intentions contained in this Annual Report or in our other filings with the SEC that are not historical.

Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition.

You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.

PART I

 

Item 1. Business.

In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company and (iii) references to “San Mateo” refer to San Mateo Midstream, LLC, our midstream joint venture with a subsidiary of Five Point Energy LLC (“Five Point”). For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report.

General

We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations, primarily through our midstream joint venture, San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.

We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million.

On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock.

Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies:

•focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin;

•identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties;

•continue to improve operational and cost efficiencies;

•identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo;

•maintain our financial discipline;

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•return capital to shareholders through our dividend policy;

•pursue opportunistic acquisitions, divestitures and joint ventures; and

•provide the energy that society needs and do so in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices.

Despite the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 in 2020, which led to a very challenging oil and natural gas price environment, global oil demand and oil and natural gas prices improved significantly during 2021. These factors, along with the successful execution of our business strategies, led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2021, as well as to increases in our oil and natural gas revenues and cash flows. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”). In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down borrowings, initiating and increasing a quarterly cash dividend and earning performance incentives from Five Point. Further, we concluded several important financing transactions in 2021, including extending the maturity of and significantly increasing the borrowing base under our Credit Agreement (as defined below) and increasing the lender commitments under the San Mateo Credit Facility (as defined below). San Mateo also achieved several important milestones in 2021, including the addition of produced water disposal capacity and being awarded several new customer contracts. These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position.

2021 Highlights

Increased Oil, Natural Gas and Oil Equivalent Production

For the year ended December 31, 2021, we achieved record oil, natural gas and average daily oil equivalent production. In 2021, we produced 17.8 million Bbl of oil, an increase of 12%, as compared to 15.9 million Bbl of oil produced in 2020. We also produced 81.7 Bcf of natural gas, an increase of 18% from 69.5 Bcf of natural gas produced in 2020. Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, an increase of 15%, as compared to 75,175 BOE per day, including 43,526 Bbl of oil per day and 189.9 MMcf of natural gas per day, for the year ended December 31, 2020. The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2021, which offset declining production in the Eagle Ford and Haynesville shales. Oil production comprised 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2021 as compared to 58% in 2020.

Increased Oil, Natural Gas and Oil Equivalent Reserves

At December 31, 2021, our estimated total proved oil and natural gas reserves were 323.4 million BOE, including 181.3 million Bbl of oil and 852.5 Bcf of natural gas, an increase of 20% from 270.3 million BOE, including 159.9 million Bbl of oil and 662.3 Bcf of natural gas, at December 31, 2020. The Standardized Measure of our total proved oil and natural gas reserves increased 176% from $1.58 billion at December 31, 2020 to $4.38 billion at December 31, 2021. The PV-10 of our total proved oil and natural gas reserves increased 223% from $1.66 billion at December 31, 2020 to $5.35 billion at December 31, 2021. The increases in our Standardized Measure and PV-10 were primarily a result of the significantly higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2021, as compared to December 31, 2020, but also due to the 20% increase in our total proved oil and natural gas reserves at December 31, 2021, as compared to December 31, 2020. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.”

At December 31, 2021, proved developed reserves included 102.2 million Bbl of oil and 546.2 Bcf of natural gas, and proved undeveloped reserves included 79.1 million Bbl of oil and 306.4 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 60% and 56%, respectively, of our total proved oil and natural gas reserves at December 31, 2021. Proved developed reserves and proved oil reserves comprised 46% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2020. The improvement in proved developed reserves as a percentage of our total proved oil and natural gas reserves to 60% at December 31, 2021 from 46% at December 31, 2020 was primarily attributable to the development and conversion of approximately 40.1 million BOE of our proved undeveloped reserves to proved developed reserves in the Delaware Basin in 2021.

Operational Highlights

We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage

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operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2022.

We completed and began producing oil and natural gas from 97 gross (48.2 net) wells in the Delaware Basin in 2021, including 47 gross (44.2 net) operated and 50 gross (4.0 net) non-operated wells. At December 31, 2021, our total acreage position in the Delaware Basin was approximately 237,200 gross (124,800 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the Wolf and Jackson Trust asset areas in Loving County, Texas. Our Delaware Basin properties are the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 19% to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021, as compared to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020. We expect our Delaware Basin production to increase in 2022 as we continue the delineation and development of these asset areas.

During 2021, we achieved all five significant and important operational milestones in the Delaware Basin we set at the beginning of the year. These five operational milestones (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) were each achieved when we turned to sales:

•the second group of Rodney Robinson wells in the western portion of our Antelope Ridge asset area, in March 2021; these four Rodney Robinson wells have produced in aggregate approximately 1.5 million BOE in 11 months of production;

•the first 13 Voni wells, all of which were 2.3-mile laterals, in the western portion of the Stateline asset area in a staggered fashion during April and May 2021; these 13 Voni wells have produced in aggregate approximately 5.2 million BOE in eight months of production;

•four wells in the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) in July 2021; these four wells have produced in aggregate approximately 0.7 million BOE in seven months of production;

•the second group of 13 Boros wells in the eastern portion of the Stateline asset area in a staggered fashion at various times primarily throughout September 2021; these 13 Boros wells have produced in aggregate approximately 2.2 million BOE in five months of production; and

•nine additional wells in the Greater Stebbins Area in December 2021.

In addition to achieving these five key operational milestones, further operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2021 included:

•the fully realized transition to drilling longer laterals, whereby 98% of the operated horizontal wells we turned to sales in 2021 had lateral lengths of two miles or greater, as compared to 74% in 2020, 8% in 2019 and only one two-mile lateral in 2018;

•the continuing improvement in capital efficiency as demonstrated by our average drilling and completion costs for all operated horizontal wells turned to sales of approximately $670 per lateral foot in 2021, a decrease of 21% as compared to $850 per lateral foot in 2020, a decrease of 42% as compared to average drilling and completion costs of $1,165 per lateral foot in 2019 and a decrease of 56% as compared to average drilling and completion costs of $1,528 per lateral foot in 2018;

•capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2021 of $513 million, which was below our original estimated range for 2021 D/C/E capital expenditures of $525 to $575 million as provided on February 23, 2021 and our revised estimated range for 2021 D/C/E capital expenditures of $535 to $565 million as provided on October 26, 2021, despite the acceleration of 11 Voni well completions forward into the fourth quarter of 2021 and the addition of a fifth operated drilling rig;

•record-low annual unit operating costs for lease operating expenses of $3.46 per BOE;

•general and administrative expenses of $3.06 per BOE, which were the second lowest general and administrative expenses we have achieved on an annual basis, as compared to a record low $2.27 per BOE in 2020. These 2021 general and administrative expenses were achieved despite the impact of increased cash-settled stock compensation costs and the reinstatement of employee compensation beginning in March 2021, which had been previously reduced beginning in March 2020 in response to the significantly lower oil and natural gas price environment at that time.

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Capital Resources and Financing Highlights

During 2021, we achieved several significant and important capital resources objectives we set at the beginning of the year. These objectives included:

•the generation of free cash flow in all four quarters of 2021;

•the net repayment of $340.0 million in borrowings under our revolving credit facility, resulting in outstanding borrowings of $100.0 million at December 31, 2021;

•the adoption of a dividend policy in the first quarter of 2021 pursuant to which we initiated a quarterly cash dividend of $0.025 per share of common stock and the subsequent amendment of that dividend policy in the fourth quarter of 2021, pursuant to which we doubled the quarterly cash dividend to $0.05 per share of common stock; and

•the receipt of $48.6 million in performance incentives directly from Five Point;

In addition, we concluded several important financing transactions in 2021 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included:

•the closing of our fourth amended and restated credit agreement (the “Credit Agreement”) in November 2021 to (i) extend the maturity date by three years to October 31, 2026 from October 31, 2023 previously, (ii) increase the borrowing base by 50% to $1.35 billion, as compared to $900.0 million previously, (iii) reaffirm the elected borrowing commitment at $700.0 million, (iv) reaffirm the maximum facility amount at $1.5 billion and (v) add three new banks to our lending group; and

•the amendment of San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) in June 2021 to increase the lender commitments under the revolving credit facility to $450.0 million from $375.0 million and an accordion feature that provides for potential increases in lender commitments to up to $700.0 million.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information regarding these financing transactions.

Midstream Highlights

San Mateo achieved strong operating results in 2021, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes, all as compared to 2020. Volumes for the years ended December 31, 2021 and 2020 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point.

During 2021, San Mateo closed seven new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing, oil gathering and transportation and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. For example, San Mateo was able to keep its gathering, processing and disposal systems operational throughout the historically prolonged cold weather conditions experienced in New Mexico and Texas during Winter Storm Uri in February 2021.

At December 31, 2021, San Mateo’s midstream system included:

•Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity in San Mateo’s cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large-diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico;

•Oil Assets: Three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 90 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains Marketing, L.P. (“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and

•Produced Water Assets: 14 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 370,000 Bbl per day and approximately 130 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.

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Environmental, Social and Governance (“ESG”) Initiatives 

We maintain an active ESG program and continued working in 2021 to improve upon our various ESG efforts. In May 2021, we published sustainability metrics aligned with standards developed by the Sustainability Accounting Standards Board (“SASB”), which we subsequently updated in July 2021. In December 2021, we issued our inaugural Sustainability Report highlighting the results of our 2020 ESG progress and achievements.

In 2020, we grew gross operated oil production by 13% and gross operated natural gas production by 19%, as compared to 2019, while still reducing our environmental impact and continuing our strong safety record. Highlights from our 2020 ESG initiatives include:

•Decreased emissions intensity by 19% and flaring intensity by 38%, as compared to 2019;

•Decreased consumption of fresh water by 49%, as compared to 2019;

•Transported 96% of operated produced water and 65% of operated produced oil by pipeline;

•Incurred no employee lost time incidents during more than 2.1 million employee man-hours from 2017 to 2020;

•Provided approximately 15,000 hours of employee continuing education, equating to approximately 55 hours per employee; and

•Revised the mandate of the Board of Directors’ Environmental, Social and Corporate Governance Committee to enhance the focus, oversight and support for our ESG efforts and to measure improvements.

Exploration and Production Segment

Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2021, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions.

The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2021.

															Producing												Total Identified												Estimated Net Proved
															Wells												Drilling Locations(1)												Reserves(2)												Avg. Daily
			Gross						Net						Gross						Net						Gross						Net												%						Production
			Acreage						Acreage																														MBOE(3)						Developed						(BOE/d)(3)
Southeast New Mexico/West Texas:
Delaware Basin(4)			237,200						124,800						944						468.1						4,381						1,534						312,018						58.6						80,534
South Texas:
Eagle Ford(5)			27,400						25,100						131						110.5						208						175						5,663						100.0						2,126
Northwest Louisiana
Haynesville			16,700						9,100						233						18.3						161						15						4,848						82.6						3,334
Cotton Valley(6)			16,100						14,900						63						39.6						154						35						868						100.0						182
Area Total(7)			19,100						17,700						296						57.9						315						50						5,716						85.3						3,516
Total			283,700						167,600						1,371						636.5						4,904						1,759						323,397						59.8						86,176

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(1)Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2021. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2021, approximately two-thirds of these identified drilling locations were expected to be horizontal laterals with lateral lengths of approximately two miles or greater, and approximately 80% are expected to have lateral lengths of approximately 1.5 miles or greater. At December 31, 2021, these engineered drilling locations included 358 gross (136 net) operated and non-operated locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon and Delaware formations, in the Delaware Basin and only eight gross (0.4 net) locations to which we have assigned proved undeveloped reserves in the Haynesville shale. At December 31, 2021, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale.

(2)These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference.

(3)Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

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(4)Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon and Avalon plays on our acreage in the Delaware Basin at December 31, 2021.

(5)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. In January 2022, the two wells and associated acreage in Zavala County, Texas, which included 55 gross (55 net) engineered locations, were divested.

(6)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(7)Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations.

We are active both as an operator and as a non-operating co-working interest owner with various industry participants. At December 31, 2021, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2021, we also were the operator for almost all of our Eagle Ford acreage and approximately half of our Haynesville acreage.

While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves.

Southeast New Mexico and West Texas — Delaware Basin

The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but, in recent years, the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations.

In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon, Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D.

At December 31, 2021, our total acreage position in Southeast New Mexico and West Texas was approximately 237,200 gross (124,800 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. These acreage totals included approximately 39,700 gross (22,600 net) acres in our Ranger asset area in Lea County, 64,500 gross (26,000 net) acres in our Arrowhead asset area in Eddy County, 47,500 gross (25,900 net) acres in our Rustler Breaks asset area in Eddy County, 24,700 gross (15,700 net) acres in our Antelope Ridge asset area in Lea County, 14,400 gross (10,700 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County and 42,900 gross (20,500 net) acres in our Twin Lakes asset area in Lea County at December 31, 2021. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2021, our acreage position in the Delaware Basin was approximately 75% held by existing production. Excluding the Twin Lakes asset area, where at December 31, 2021 we had drilled only three vertical operated wells and two horizontal operated wells, and the undeveloped acreage acquired in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, our acreage position in the Delaware Basin was approximately 86% held by existing production at December 31, 2021.

During the year ended December 31, 2021, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 97 gross (48.2 net) wells in the Delaware Basin, including 47

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gross (44.2 net) operated horizontal wells and 50 gross (4.0 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2021, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, two benches of the Second Bone Spring, two benches of the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the First Bone Spring and the Wolfcamp B.

As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2021. Our average daily oil equivalent production from the Delaware Basin increased approximately 19% to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021, as compared to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020.

At December 31, 2021, approximately 96% of our estimated total proved oil and natural gas reserves, or 312.0 million BOE, was attributable to the Delaware Basin, including approximately 177.1 million Bbl of oil and 809.3 Bcf of natural gas, a 19% increase, as compared to 261.9 million BOE for the year ended December 31, 2020. Our Delaware Basin proved reserves at December 31, 2021 comprised approximately 98% of our proved oil reserves and 95% of our proved natural gas reserves, as compared to approximately 98% of our proved oil reserves and 96% of our proved natural gas reserves at December 31, 2020.

At December 31, 2021, we had identified 4,381 gross (1,534 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations. These locations include 2,204 gross (1,350 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2021, approximately two-thirds of these identified drilling locations are expected to have horizontal lateral lengths of approximately two miles or greater and approximately 80% are expected to have horizontal lateral lengths of approximately 1.5 miles or greater. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations, at December 31, 2021, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2021, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2021, these potential future drilling locations included 358 gross (136 net) operated and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon and Delaware formations, to which we have assigned proved undeveloped reserves.

At December 31, 2021, we were operating five drilling rigs in the Delaware Basin. At February 22, 2022, we had contracted a sixth drilling rig to begin drilling operations on recently acquired acreage in the western portion of our Ranger asset area in Lea County, New Mexico. We expect to operate six drilling rigs across our various Delaware Basin asset areas throughout the remainder of 2022, but these six drilling rigs are expected to have an increased focus on our Rustler Breaks, Antelope Ridge and Ranger asset areas in 2022, as compared to 2021. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2022.

Antelope Ridge Asset Area - Lea County, New Mexico

At the end of the first quarter of 2021, we achieved the first of the five operational milestones we set for Matador in 2021 when we turned to sales four gross (3.8 net) wells on the Rodney Robinson leasehold. These wells were the second group of wells drilled on the Rodney Robinson leasehold, which was acquired in the BLM Acquisition. We did not turn to sales any other operated wells in other portions of the Antelope Ridge asset area during 2021, although we did participate in the drilling and completion of 20 gross (1.1 net) non-operated wells that were turned to sales in the Antelope Ridge asset area during 2021.

The 1,300 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired in the BLM Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. The four Rodney Robinson wells, which included two Wolfcamp A-XY completions and two Third Bone Spring

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completions, were turned to sales late in the first quarter of 2021 and were all two-mile laterals. These four Rodney Robinson wells have produced in aggregate approximately 1.5 million BOE in approximately 11 months of production despite being produced on restricted chokes throughout their early producing lives. We drilled nine additional Rodney Robinson wells in the fall of 2021, and these nine wells are expected to be turned to sales late in the first quarter of 2022.

We turned to sales the initial six Rodney Robinson wells in the western portion of the Antelope Ridge asset area in late March 2020. In aggregate, these six wells have produced approximately 4.3 million BOE in approximately 22 months of production.

Rustler Breaks Asset Area - Eddy County, New Mexico

In the Rustler Breaks asset area, we turned to sales 13 gross (0.9 net) non-operated wells during 2021. We did not turn to sales any operated wells during 2021, but at December 31, 2021, we had drilled or were drilling six operated wells in the Rustler Breaks asset area, all of which are expected to be turned to sales in the second quarter of 2022. We expect the Rustler Breaks asset area to be an area of increased operational focus for Matador throughout 2022.

Arrowhead Asset Area - Eddy County, New Mexico

In the Arrowhead asset area, we turned to sales 13 gross (11.5 net) operated wells and 14 gross (1.6 net) non-operated wells during 2021.

During the third quarter of 2021, we achieved the third of the five operational milestones we set for Matador in 2021 when we turned to sales four wells, all of which were two-mile laterals completed in the Second Bone Spring formation, in the Greater Stebbins Area. These four wells have produced in aggregate approximately 0.7 million BOE in seven months of production. At the end of the fourth quarter of 2021, we achieved the fifth and final operational milestone we set for Matador in 2021 when we turned to sales nine wells, all of which were two-mile laterals completed in the Third Bone Spring, Wolfcamp A-XY and Wolfcamp B formations, in the Greater Stebbins Area in December 2021.

Ranger and Twin Lakes Asset Areas - Lea County, New Mexico

In the Ranger asset area, we turned to sales two gross (1.3 net) operated wells and three gross (0.4 net) non-operated wells. We did not turn to sales any operated or non-operated wells in the Twin Lakes asset area during 2021.

We were pleased with the performance from the first two Uncle Ches wells turned to sales in the Second Bone Spring in the Ranger asset area in the first quarter of 2021. In aggregate, these two wells tested 4,053 BOE per day (90% oil) during 24-hour initial potential (“IP”) tests conducted after these wells were equipped with electric submersible pumps (“ESP”). The high (90%) oil cut and low water cut (approximately one Bbl of water per Bbl of oil produced) exhibited by these wells should enhance their economics. We drilled two additional Uncle Ches wells in the Ranger asset area in the fall of 2021, also Second Bone Spring completions, which were turned to sales in mid-January 2022.

Stateline Asset Area - Eddy County, New Mexico

We operated two drilling rigs in our Stateline asset area for the majority of 2021. In early September 2018, we acquired the Stateline asset area in southern Eddy County, New Mexico as part of the BLM Acquisition. The Stateline asset area includes approximately 2,900 gross and net leasehold acres prospective for multiple geologic targets. The federal leases provide an 87.5% NRI. The large majority of the Stateline asset area acreage has shown to be conducive to drilling longer laterals of up to two miles or more, utilizing central facilities and multi-well pad development. We have been developing this acreage block drilling two-mile laterals on the eastern side of the leasehold and approximately 2.3-mile laterals on the western side of the leasehold. We began drilling operations in the Stateline asset area just before the end of 2019 and, at the end of the third quarter of 2020, we turned to sales our first 13 gross (13.0 net) wells on the Boros tract in the eastern portion of the Stateline asset area. In aggregate, the first 13 Boros wells have produced approximately 7.2 million BOE in approximately 15 months of production.

After finishing drilling operations on the first 13 Boros wells in 2020, we began drilling operations on the Voni tract in the western portion of the Stateline asset area, and in the second quarter of 2021, we achieved the second of the five operational milestones we set for Matador in 2021 when we turned to sales our first 13 gross (12.7 net) wells on the Voni tract in the western portion of the Stateline asset area. The 13 Voni wells had completed lateral lengths of approximately 12,000 feet, or about 2.3-miles, making them the longest laterals Matador has completed to date. The 13 Voni wells included one First Bone Spring completion, four Second Bone Spring completions, four Wolfcamp A-XY completions and four Wolfcamp A-Lower completions. Of particular note, the Voni Federal #216H well, a Wolfcamp A-Lower completion, tested 5,073 BOE per day (60% oil), which was the highest 24-hour IP Matador has achieved to date in any formation in the Delaware Basin. These 13 Voni wells have produced in aggregate approximately 5.2 million BOE in approximately eight months of production, despite a number of these wells being produced on restricted chokes early in their producing lives.

After finishing drilling operations on the first 13 Voni wells, we began drilling operations on the next 13 Boros wells, and in the third quarter of 2021, we achieved the fourth of the five operational milestones we set for Matador in 2021 when we

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turned to sales our second group of 13 gross (13.0 net) wells on the Boros tract in the eastern portion of the Stateline asset area. These 13 Boros wells have produced in aggregate approximately 2.2 million BOE in five months of production. Drilling and completion costs for the 26 Stateline wells turned to sales during 2021 averaged $628 per completed lateral foot, the lowest costs we have achieved in any of our asset areas.

In addition, during 2021, we drilled and completed our second group of 11 wells on the Voni tract on the western portion of the Stateline leasehold. These 11 Voni wells are expected to have completed lateral lengths of approximately 12,000 feet and were turned to sales in the first quarter of 2022.

Wolf and Jackson Trust Asset Areas - Loving County, Texas

In the Wolf and Jackson Trust asset areas, we turned to sales two gross (1.9 net) operated wells during 2021. At December 31, 2021, we were in the process of completing three two-mile lateral wells in the Second Bone Spring formation, and these three wells were turned to sales in February 2022.

South Texas — Eagle Ford Shale and Other Formations

The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate.

At December 31, 2021, our properties included approximately 27,400 gross (25,100 net) acres in the Eagle Ford shale play in South Texas. We believe that approximately 89% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. All of our Eagle Ford leasehold was held by existing production at December 31, 2021.

We did not conduct any operated or non-operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2021. In fact, as of December 31, 2021, we had not completed any new operated wells in the Eagle Ford shale since the second quarter of 2019. As a result, our average daily oil equivalent production from the Eagle Ford shale decreased 12% to 2,126 BOE per day, including 1,528 Bbl of oil per day and 3.6 MMcf of natural gas per day, during 2021, as compared to 2,412 BOE per day, including 1,840 Bbl of oil per day and 3.4 MMcf of natural gas per day, during 2020. For the year ended December 31, 2021, 2% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 3% for the year ended December 31, 2020.

At December 31, 2021, approximately 2% of our estimated total proved oil and natural gas reserves, or 5.7 million BOE, was attributable to the Eagle Ford shale, including approximately 4.1 million Bbl of oil and 9.1 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 2% of our proved oil reserves and 1% of our proved natural gas reserves at December 31, 2021, essentially unchanged from December 31, 2020.

At December 31, 2021, we had identified 208 gross (175 net) engineered locations for potential future drilling on our Eagle Ford acreage, including 55 gross (55 net) engineered locations in Zavala County that were divested in January 2022. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral lengths ranging from one mile to almost two miles. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors.

These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our South Texas acreage may also be prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly oil and liquids. At December 31, 2021, we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations, even though activity from other operators in these formations around our South Texas acreage position has demonstrated the prospectivity of these intervals.

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Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations

The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%.

We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2021, although we did participate in the drilling and completion of seven gross (less than 0.1 net) non-operated Haynesville shale wells that were turned to sales in 2021. In the first quarter of 2020, we leased 2,800 net acres of our minerals in the southern portion of our Pine Island asset area to a third party and retained royalty interests ranging from 18% to 20%. This lessee turned to sales four Haynesville shale wells drilled on these interests in the first half of 2021. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2022.

At December 31, 2021, we held approximately 19,100 gross (17,700 net) acres in Northwest Louisiana, including 16,700 gross (9,100 net) acres in the Haynesville shale play and 16,100 gross (14,900 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,800 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2021.

For the year ended December 31, 2021, approximately 4% of our average daily oil equivalent production, or 3,516 BOE per day, including nine Bbl of oil per day and 21.0 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2020, approximately 7% of our average daily oil equivalent production, or 5,241 BOE per day, including eight Bbl of oil per day and 31.4 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2021, approximately 9% of our daily natural gas production, or 21.0 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2020, approximately 17% of our daily natural gas production, or 31.4 MMcf of natural gas per day, was attributable to these properties. At December 31, 2021, approximately 2% of our estimated total proved reserves, or 5.7 million BOE, was attributable to our properties in Northwest Louisiana.

At December 31, 2021, we had identified 161 gross (15 net) engineered locations for potential future drilling in the Haynesville shale play and 154 gross (35 net) engineered locations for potential future drilling in the Cotton Valley formation. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral lengths ranging from one mile to two miles, with most being two miles. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other factors.

Midstream Segment

Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.

Southeast New Mexico and West Texas — Delaware Basin

On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo included (i) the Black River Processing Plant (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo and had the potential to earn up to $73.5 million in performance incentives over a five-year period, which in October 2020 was extended by an additional year. At February 22, 2022, we had earned $58.8 million of the potential $73.5 million in performance incentives. Through February 22, 2022, Five Point had paid $14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020 and 2021, and we may earn up to the remaining $14.7 million in San Mateo performance incentives over the next year relating to the formation of San Mateo. In connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-

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year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement.

On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we have the ability to earn up to $150.0 million in performance incentives over the next several years, plus additional performance incentives for securing volumes from third-party customers. During the fourth quarter of 2020, we met the threshold requirements to begin earning the additional $150.0 million in performance incentives from Five Point. At February 22, 2022, we had received $33.9 million of the potential $150.0 million in performance incentives. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements.

Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and facilities that have been developed in the Greater Stebbins Area and the Stateline asset area.

Natural Gas Gathering and Processing Assets

The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks.

During the third quarter of 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2021, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area.

In September 2020, San Mateo completed and placed in service approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). At December 31, 2021, San Mateo was gathering or transporting all our operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf asset area.

In addition, in early 2018, San Mateo completed a natural gas liquids (“NGL”) pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting the NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise.

In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area, including a cryogenic natural gas processing plant and approximately six miles of high-pressure gathering pipelines.

At December 31, 2021, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2021, San Mateo gathered approximately 86.1 Bcf of natural gas, an increase of 17%, as compared to 73.9 Bcf of natural gas gathered during the year ended December 31, 2020. In addition, during the year ended December 31, 2021, San Mateo processed approximately 77.6 Bcf of natural gas at the Black River Processing Plant, an increase of 28%, as compared to 60.8 Bcf of natural gas processed during the year ended

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December 31, 2020. Natural gas gathering and processing volumes for the years ended December 31, 2021 and 2020 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues.

Crude Oil Gathering and Transportation Assets

San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within a joint development area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets.

In 2020, San Mateo completed and placed into service (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area via approximately 19 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the Wolf asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2021, we estimated we had on pipe almost all of our oil production from the Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area.

At December 31, 2021, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains and two trucking facilities. During the year ended December 31, 2021, the San Mateo Oil Pipeline Systems had throughput of approximately 14.9 million Bbl of oil, an increase of 28%, as compared to throughput of approximately 11.6 million Bbl of oil during the year ended December 31, 2020.

Produced Water Gathering and Disposal Assets

During 2021, San Mateo placed into service one commercial salt water disposal well in the Greater Stebbins Area, bringing San Mateo’s commercial salt water disposal well count in the Greater Stebbins Area to three. In addition to its three commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at February 22, 2022, San Mateo had eight commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the Wolf asset area and produced water gathering systems in the Stateline, Rustler Breaks and Wolf asset areas and the Greater Stebbins Area. At February 22, 2022, San Mateo had designed disposal capacity of approximately 370,000 Bbl of produced water per day.

During the year ended December 31, 2021, San Mateo handled approximately 101.4 million Bbl of produced water, an increase of 20%, as compared to approximately 84.8 million Bbl of produced water handled during the year ended December 31, 2020.

South Texas / Northwest Louisiana

In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo.

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Operating Summary

The following table sets forth certain unaudited production and operating data for the years ended December 31, 2021, 2020 and 2019.

						Year Ended December 31,
						2021						2020						2019
Unaudited Production Data:
Net Production Volumes:
Oil (MBbl)						17,840						15,931						13,984
Natural gas (Bcf)						81.7						69.5						61.1
Total oil equivalent (MBOE)(1)						31,454						27,514						24,164
Average daily production (BOE/d)(1)						86,176						75,175						66,203
Average Sales Prices:
Oil, without realized derivatives (per Bbl)						$	67.58					$	37.38					$	54.34
Oil, with realized derivatives (per Bbl)						$	56.70					$	39.83					$	54.98
Natural gas, without realized derivatives (per Mcf)						$	6.06					$	2.14					$	2.17
Natural gas, with realized derivatives (per Mcf)						$	5.74					$	2.14					$	2.18
Operating Expenses (per BOE):
Production taxes, transportation and processing						$	5.69					$	3.39					$	3.82
Lease operating						$	3.46					$	3.81					$	4.85
Plant and other midstream services operating						$	1.95					$	1.51					$	1.52
Depletion, depreciation and amortization						$	10.97					$	13.15					$	14.51
General and administrative						$	3.06					$	2.27					$	3.31

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(1)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2021 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.

						Southeast New Mexico/West Texas						South Texas						Northwest Louisiana
						Delaware Basin						Eagle Ford(1)						Haynesville						Cotton Valley(2)						Total
Annual Net Production Volumes
Oil (MBbl)						17,279						558						—						3						17,840
Natural gas (Bcf)						72.7						1.3						7.3						0.4						81.7
Total oil equivalent (MBOE)(3)						29,395						776						1,217						66						31,454
Percentage of total annual net production						93.4		%				2.5		%				3.9		%				0.2		%				100.0		%
Average Net Daily Production Volumes
Oil (Bbl/d)						47,339						1,528						—						9						48,876
Natural gas (MMcf/d)						199.2						3.6						20.0						1.0						223.8
Total oil equivalent (BOE/d)						80,534						2,126						3,334						182						86,176
Average Sales Prices(4)
Oil (per Bbl)						$	67.65					$	65.41					$	—					$	64.40					$	67.58
Natural gas (per Mcf)						$	6.33					$	7.39					$	3.19					$	4.31					$	6.06
Total oil equivalent (per BOE)						$	55.43					$	59.49					$	19.16					$	27.81					$	54.06
Production Costs(5)
Lease operating, transportation and processing (per BOE)						$	4.49					$	19.51					$	4.84					$	25.69					$	4.92

__________________

(1)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022.

(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4)Excludes impact of derivative settlements.

(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

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The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2020 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. 

						Southeast  New Mexico/West Texas						South Texas						Northwest Louisiana
						Delaware Basin						Eagle Ford(1)						Haynesville						Cotton Valley(2)						Total
Annual Net Production Volumes
Oil (MBbl)						15,254						674						—						3						15,931
Natural gas (Bcf)						56.8						1.2						11.0						0.5						69.5
Total oil equivalent (MBOE)(3)						24,713						883						1,835						83						27,514
Percentage of total annual net production						89.8		%				3.2		%				6.7		%				0.3		%				100.0		%
Average Net Daily Production Volumes
Oil (Bbl/d)						41,678						1,840						—						8						43,526
Natural gas (MMcf/d)						155.1						3.4						30.1						1.3						189.9
Total oil equivalent (BOE/d)						67,522						2,412						5,015						226						75,175
Average Sales Prices(4)
Oil (per Bbl)						$	37.38					$	37.42					$	28.77					$	38.31					$	37.38
Natural gas (per Mcf)						$	2.23					$	2.82					$	1.66					$	1.69					$	2.14
Total oil equivalent (per BOE)						$	28.19					$	32.56					$	9.94					$	11.09					$	27.06
Production Costs(5)
Lease operating, transportation and processing (per BOE)						$	4.52					$	20.52					$	4.71					$	19.39					$	5.09

_________________

(1)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022.

(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4)Excludes impact of derivative settlements.

(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

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The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2019 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.

						Southeast  New Mexico/West Texas						South Texas						Northwest Louisiana
						Delaware Basin						Eagle Ford(1)						Haynesville						Cotton Valley(2)						Total
Annual Net Production Volumes
Oil (MBbl)						12,843						1,136						—						5						13,984
Natural gas (Bcf)						44.7						2.0						13.9						0.5						61.1
Total oil equivalent (MBOE)(3)						20,294						1,463						2,316						91						24,164
Percentage of total annual net production						84.0		%				6.0		%				9.6		%				0.4		%				100.0		%
Average Net Daily Production Volumes
Oil (Bbl/d)						35,184						3,113						—						15						38,312
Natural gas (MMcf/d)						122.5						5.4						38.1						1.4						167.4
Total oil equivalent (BOE/d)						55,599						4,009						6,345						250						66,203
Average Sales Prices(4)
Oil (per Bbl)						$	53.95					$	58.71					$	—					$	52.89					$	54.34
Natural gas (per Mcf)						$	2.11					$	3.45					$	2.16					$	2.17					$	2.17
Total oil equivalent (per BOE)						$	38.80					$	50.22					$	12.99					$	15.22					$	36.93
Production Costs(5)
Lease operating, transportation and processing (per BOE)						$	5.22					$	15.27					$	4.36					$	22.43					$	5.81

_________________

(1)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022.

(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4)Excludes impact of derivative settlements.

(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

Our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021 increased 14% from our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2021, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, as compared to 75,175 BOE per day for the year ended December 31, 2020. Our average daily oil production for the year ended December 31, 2021 was 48,876 Bbl of oil per day, an increase of 12% from 43,526 Bbl of oil per day for the year ended December 31, 2020. Our average daily natural gas production for the year ended December 31, 2021 was 223.8 MMcf of natural gas per day, an increase of 18% from 189.9 MMcf of natural gas per day for the year ended December 31, 2020.

Our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020 increased 14% from our total oil equivalent production of approximately 24.2 million BOE for the year ended December 31, 2019. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2020, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2020 was 75,175 BOE per day, as compared to 66,203 BOE per day for the year ended December 31, 2019. Our average daily oil production for the year ended December 31, 2020 was 43,526 Bbl of oil per day, an increase of 14% from 38,312 Bbl of oil per day for the year ended December 31, 2019. Our average daily natural gas production for the year ended December 31, 2020 was 189.9 MMcf of natural gas per day, an increase of 13% from 167.4 MMcf of natural gas per day for the year ended December 31, 2019.

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Producing Wells

The following table sets forth information relating to producing wells at December 31, 2021. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 81% in all wells that we operated at December 31, 2021. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest, and net wells represent the total of our fractional working interests owned in the gross wells. 

						Oil Wells												Natural Gas Wells												Total Wells
						Gross						Net						Gross						Net						Gross						Net
Southeast New Mexico/West Texas:
Delaware Basin(1)						784						388.4						160						79.7						944						468.1
South Texas:
Eagle Ford(2)						128						107.5						3						3.0						131						110.5
Northwest Louisiana:
Haynesville						—						—						233						18.3						233						18.3
Cotton Valley(3)						1						1.0						62						38.6						63						39.6
Area Total						1						1.0						295						56.9						296						57.9
Total						913						496.9						458						139.6						1,371						636.5

__________________

(1)Includes 212 gross (67.5 net) vertical wells that were acquired in multiple transactions.

(2)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022.

(3)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

Estimated Proved Reserves

The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2021, 2020 and 2019. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. 

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						At December 31,(1)
						2021						2020						2019
Estimated Proved Reserves Data:(2)
Estimated proved reserves:
Oil (MBbl)						181,306						159,949						147,991
Natural Gas (Bcf)						852.5						662.3						627.2
Total (MBOE)(3)						323,397						270,332						252,531
Estimated proved developed reserves:
Oil (MBbl)						102,233						69,647						59,667
Natural Gas (Bcf)						546.2						323.2						276.3
Total (MBOE)(3)						193,262						123,507						105,710
Percent developed						59.8		%				45.7		%				41.9		%
Estimated proved undeveloped reserves:
Oil (MBbl)						79,073						90,301						88,324
Natural gas (Bcf)						306.4						339.1						351.0
Total (MBOE)(3)						130,135						146,825						146,821
Standardized Measure(4) (in millions)						$	4,375.4					$	1,584.4					$	2,034.0
PV-10(5) (in millions)						$	5,347.6					$	1,658.0					$	2,248.2

__________________

(1)Numbers in table may not total due to rounding.

(2)Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2021 were $63.04 per Bbl for oil and $3.60 per MMBtu for natural gas, for the 12 months ended December 31, 2020 were $36.04 per Bbl for oil and $1.99 per MMBtu for natural gas and for the 12 months ended December 31, 2019 were $52.19 per Bbl for oil and $2.58 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold.

(3)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4)Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.

(5)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2021, 2020 and 2019 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2021, 2020 and 2019 were, in millions, $972.2, $73.6 and $214.2, respectively.

Our estimated total proved oil and natural gas reserves increased 20% from 270.3 million BOE at December 31, 2020 to 323.4 million BOE at December 31, 2021. This increase in proved oil and natural gas reserves was primarily attributable to (i) our delineation and development operations in the Delaware Basin during 2021 and (ii) the 75% increase in oil prices and the 81% increase in natural gas prices used to estimate total proved reserves at December 31, 2021, as compared to December 31, 2020. We added 33.1 million BOE in proved oil and natural gas reserves through extensions and discoveries during 2021, of which 22.4 million BOE resulted from new well locations drilled during 2021 to establish proved developed reserves and 26.9 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2021, but which were partially offset by the removal of 16.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of our properties in the Delaware Basin. As we continue to develop our Delaware Basin assets, we may reclassify some or all of this 16.3 million BOE to proved reserves at a future date. We realized approximately 41.9 million BOE in net upward revisions to prior estimates, 96% of which were attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of our properties. We also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of our properties. In addition, we realized 9.5 million BOE in net upward revisions to our proved oil and natural gas reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021.

Our proved oil reserves grew 13% from approximately 159.9 million Bbl at December 31, 2020 to approximately 181.3 million Bbl at December 31, 2021. Our proved natural gas reserves increased 29% from 662.3 Bcf at December 31, 2020 to

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852.5 Bcf at December 31, 2021. Our proved reserves to production ratio at December 31, 2021 was 10.3, an increase of 5% from 9.8 at December 31, 2020.

The Standardized Measure of our total proved oil and natural gas reserves increased 176% from $1.58 billion at December 31, 2020 to $4.38 billion at December 31, 2021. The PV-10 of our total proved oil and natural gas reserves increased 223% from $1.66 billion at December 31, 2020 to $5.35 billion at December 31, 2021. The increases in our Standardized Measure and PV-10 are primarily a result of the significantly higher weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2021, as compared to December 31, 2020, but also due to the 20% increase in our total proved oil and natural gas reserves at December 31, 2021, as compared to December 31, 2020. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2021 were $63.04 per Bbl and $3.60 per MMBtu, an increase of 75% and 81%, respectively, as compared to average oil and natural gas prices of $36.04 per Bbl and $1.99 per MMBtu used to estimate proved reserves at December 31, 2020. Our total proved reserves were made up of 56% oil and 44% natural gas at December 31, 2021 and 59% oil and 41% natural gas at December 31, 2020. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table.

The following table summarizes changes in our estimated proved developed reserves at December 31, 2021.

						Proved Developed Reserves
						(MBOE)(1)
As of December 31, 2020						123,507
Extensions and discoveries						22,427
Net acquisitions of minerals-in-place						4,907
Revisions of prior estimates						33,804
Production						(31,454)
Conversion of proved undeveloped to proved developed						40,071
As of December 31, 2021						193,262

__________________

(1)    Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Our proved developed oil and natural gas reserves increased 56% from 123.5 million BOE at December 31, 2020 to 193.3 million BOE at December 31, 2021. We added 22.4 million BOE in proved developed reserves through extensions and discoveries during 2021, which resulted from new well locations drilled during 2021 to establish proved reserves. We realized approximately 33.8 million BOE in net upward revisions to prior estimates, 97% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of our producing properties. We also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of our producing properties. In addition, we converted 40.1 million BOE of our proved undeveloped reserves to proved developed reserves through our development activities in the Delaware Basin during 2021, primarily in our Stateline asset area, in the Greater Stebbins Area and in the Rodney Robinson leasehold in the Antelope Ridge asset area. In addition, we realized 4.9 million BOE in net upward revisions to our proved developed reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. These cumulative net upward revisions of 101.2 million BOE to our proved developed reserves exceeded by 3.2 times our total oil and natural gas production of 31.5 million BOE in 2021.

Our proved developed oil reserves increased 47% from 69.6 million Bbl at December 31, 2020 to 102.2 million Bbl at December 31, 2021. Our proved developed natural gas reserves increased 69% from 323.2 Bcf at December 31, 2020 to 546.2 Bcf at December 31, 2021. Proved developed reserves constituted 60% of our total proved oil and natural gas reserves at December 31, 2021, as compared to 46% at December 31, 2020.

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The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2021.

						Proved Undeveloped Reserves
						(MBOE)(1)
As of December 31, 2020						146,825
Extensions and discoveries						10,647
Net acquisitions of minerals-in-place						4,622
Revisions of prior estimates						8,112
Conversion of proved undeveloped to proved developed						(40,071)
As of December 31, 2021						130,135

__________________

(1)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Our proved undeveloped oil and natural gas reserves decreased 11% from 146.8 million BOE at December 31, 2020 to 130.1 million at December 31, 2021. We added 26.9 million BOE in proved undeveloped reserves through extensions and discoveries during 2021, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2021 but which were partially offset by the removal of 16.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of the properties in the Delaware Basin. We realized approximately 8.1 million BOE in net upward revisions to our prior estimates of proved undeveloped reserves, 90% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of our proved undeveloped locations. We also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of our proved undeveloped locations. In addition, we realized 4.6 million BOE in net upward revisions to our proved undeveloped reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. During 2021, we also converted 40.1 million BOE of our proved undeveloped reserves to proved developed reserves through our development activities in the Delaware Basin during 2021, primarily in our Stateline asset area, in the Greater Stebbins Area and in the Rodney Robinson leasehold in the Antelope Ridge asset area.

At December 31, 2021, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2021 within five years of booking these reserves. The following table sets forth, since 2018, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands).

																								Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
						Proved Undeveloped Reserves Converted to Proved Developed Reserves
						Oil						Natural Gas						Total
						(MBbl)						(Bcf)						(MBOE)(1)
2018						16,009						61.7						26,283						$	356,830
2019						13,832						58.8						23,629						318,609
2020						16,256						76.1						28,944						257,590
2021						23,965						96.6						40,071						240,664
Total						70,062						293.2						118,927						$	1,173,693

__________________

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

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The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2021.

						Net Proved Reserves(1)
						Oil						Natural Gas						Oil Equivalent						Standardized Measure(2)						PV-10(3)
						(MBbl)						(Bcf)						(MBOE)(4)						(in millions)						(in millions)
Southeast New Mexico/West Texas:
Delaware Basin						177,137						809.3						312,018						$	4,268.7					$	5,217.2
South Texas:
Eagle Ford(5)						4,146						9.1						5,663						78.8						96.2
Northwest Louisiana
Haynesville						—						29.1						4,848						26.3						32.2
Cotton Valley(6)						23						5.0						868						1.6						2.0
Area Total						23						34.1						5,716						27.9						34.2
Total						181,306						852.5						323,397						$	4,375.4					$	5,347.6

__________________

(1)Numbers in table may not total due to rounding.

(2)Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.

(3)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2021 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2021 were approximately $972.2 million.

(4)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(5)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022.

(6)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

Technology Used to Establish Reserves

Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods.

Internal Control Over Reserves Estimation Process

We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Reserves Manager was primarily responsible for overseeing the preparation of our reserves estimates in 2021. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from Texas Tech University, is a licensed Professional

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Engineer in the state of Texas and has over nine years of industry experience. Our Reserves Manager works under the direct supervision of our Senior Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has over 14 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and U.S. generally accepted accounting principles (“GAAP”) requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of our Board of Directors as well.

Acreage Summary

The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2021.

						Developed Acres												Undeveloped Acres												Total Acres
						Gross						Net						Gross						Net						Gross						Net
Southeast New Mexico/West Texas:
Delaware Basin						184,000						93,000						53,200						31,800						237,200						124,800
South Texas:
Eagle Ford						27,400						25,100						—						—						27,400						25,100
Northwest Louisiana:
Haynesville						16,700						9,100						—						—						16,700						9,100
Cotton Valley						16,100						14,900						—						—						16,100						14,900
Area Total(1)						19,100						17,700						—						—						19,100						17,700
Total						230,500						135,800						53,200						31,800						283,700						167,600

__________________

(1)Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana.

Undeveloped Acreage Expiration

The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2021 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2027 and beyond totals 6,700 net acres, all of which is in the Delaware Basin. All of our leasehold in the Eagle Ford shale in South Texas and in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2021.

						Acres												Acres												Acres												Acres												Acres
						Expiring 2022												Expiring 2023												Expiring 2024												Expiring 2025												Expiring 2026
						Gross						Net						Gross						Net						Gross						Net						Gross						Net						Gross						Net
Southeast New Mexico/West Texas:
Delaware Basin(1)						24,100						11,100						5,500						5,300						8,900						3,100						2,900						2,800						5,200						2,800
Total						24,100						11,100						5,500						5,300						8,900						3,100						2,900						2,800						5,200						2,800

__________________

(1)Approximately 65% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling activities or by paying an additional lease bonus, where applicable.

Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2021,

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our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. At December 31, 2021, less than 2% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage.

Drilling Results

The following table summarizes our drilling activity for the years ended December 31, 2021, 2020 and 2019. 

						Year Ended December 31,
						2021												2020												2019
						Gross						Net						Gross						Net						Gross						Net
Development Wells
Productive						96						40.2						89						44.5						147						62.0
Dry						—						—						—						—						—						—
Exploration Wells
Productive						8						8.0						4						3.3						25						13.3
Dry						—						—						—						—						—						—
Total Wells
Productive						104						48.2						93						47.8						172						75.3
Dry						—						—						—						—						—						—

At December 31, 2021, we had a total of 31 gross (27.0 net) development wells and two gross (1.1 net) exploration wells that were in the process of being drilled, being completed or awaiting completion operations.

Marketing and Customers

Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids.

Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees.

The prices we receive for our oil and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”), weather conditions, including hurricanes in the Gulf Coast region and severe cold weather in the Delaware Basin, oil and natural gas storage levels, transportation and refinery capacity constraints, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, including Russia, Ukraine, China and the Middle East, domestic or global health concerns such as COVID-19, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”

The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate (“WTI”) oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—An increase in

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the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.”

For the years ended December 31, 2021, 2020 and 2019, we had three, two and two significant purchasers, respectively, that accounted for approximately 72%, 65% and 67%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference.

Title to Properties

We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.”

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. As discussed below in “—Regulation,” the Biden administration has issued certain orders and implemented certain policies limiting or delaying the issuance of federal drilling permits and other necessary federal approvals. Although some of these restrictions have lapsed at December 31, 2021, the impact of federal actions related to the oil and natural gas industry remains unclear, and should those or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted.

Seasonality

Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.”

Competition

The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability.

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Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment.

Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations.

The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.”

Regulation

Oil and Natural Gas Regulation

Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations.

Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. In January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior providing for a 60-day pause limiting the authority of local offices of the Bureau of Land Management (“BLM”) to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Administration Federal Lease Orders”). In 2019, 2020 and 2021, an environmental group filed three lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico (the “Lease Sale Litigation”). The Lease Sale Litigation challenges the BLM’s decision to hold the lease sales based on alleged defects in the environmental reviews conducted under the National Environmental Policy Act (“NEPA”) in conjunction with those sales. In 2020, the New Mexico federal district court dismissed the case pending there. That decision was appealed to the Tenth Circuit, but the appeal was voluntarily dismissed in 2021. In February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses. The BLM has not announced when it will complete the additional NEPA review, and the outcome of that review with regard to the leases at issue and any related drilling permits is uncertain.

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In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making (the “Social Cost of Carbon Litigation”). Among the decisions impacted by the executive order were NEPA reviews conducted in connection with oil and gas leasing and permitting decisions by the BLM. In February 2022, the Louisiana federal district court issued an injunction prohibiting the federal government, including the Department of Interior and BLM, from utilizing the challenged social cost of greenhouse gases factor as a part of NEPA reviews. Subsequent to that decision, the federal government submitted filings in the federal district court indicating that the court’s injunction could, among other things, result in an indefinite delay of future lease sales and permit approvals due to inconsistencies between the NEPA analyses and the court’s ruling.

Although some of the restrictions in the Biden Administrative Federal Lease Orders have lapsed at December 31, 2021, the impact of federal actions related to the oil and natural gas industry, including those in response to the Lease Sale Litigation and Social Cost of Carbon Litigation, remains unclear, and should limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”

Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 70 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction.

In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated.

As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing

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regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative.

The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations.

In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder.

The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.”

Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays.

U.S. Federal and State Taxation

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico.

In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the federal level. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. Any such changes in federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and gas exploration and development, and any such changes could negatively affect our financial condition, results of operations, and cash flows. The Build Back Better Act (H.R. 5376) was passed by the U.S. House of Representatives on November 19, 2021 and contains certain U.S. federal income tax changes and certain additional taxes and fees.

Changes to state or federal tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.”

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Hydraulic Fracturing Policies and Procedures

We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”

The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage).

Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures.

The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and employ rigorous safety procedures to protect the environment and work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures.

While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced water in certain of our Delaware Basin asset areas. Recycling produced water mitigates the need for produced water disposal and also provides cost savings to us. Furthermore, an increasing percentage of the water used in our hydraulic fracturing operations is sourced from recycled produced water from our wells or other sources, further reducing the amount of fresh water in our hydraulic fracturing operations.

Environmental, Health and Safety Regulation

The exploration, development, production, gathering and processing of oil and natural gas, including the operation of produced water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (the “RCRA”), the Clean Air Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us.

The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore

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facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action.

The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the “EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019, however, and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR defined what waters qualify as navigable waters of the United States and are under CWA jurisdiction. This new rule has generally been viewed as narrowing the scope of WOTUS as compared to the 2015 rule, but there is currently litigation in multiple federal district courts challenging the rescission of the 2015 rule and the promulgation of the NWPR.

Separately, in April 2020, a Montana federal judge vacated the Corps’ Nationwide Permit (“NWP”) 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with the U.S. Fish and Wildlife Service (the “USFWS”) under the Endangered Species Act (the “ESA”) regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines, and that order was partially vacated in the Ninth Circuit Court of Appeals as moot, based on the Corps’ re-issuance of NWPs in 2021. The Corps has now issued a new set of NWPs, which would replace the NWPs for dredge or fill discharges into WOTUS that the Corps last issued and made available in 2017, but has not elected not to consult with the USFWS. The re-issued NWPs have similarly been subject to the same legal challenges based on the lack of a formal ESA consultation.

CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA.

RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes.

The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. While the United States exited the Paris

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Agreement in November 2020, effective February 19, 2021, President Biden caused the United States to rejoin the Paris Agreement. In April 2021, President Biden set a new goal for the United States to achieve a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy. In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the New Mexico Oil Conservation Division (the “NMOCD”) implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The New Mexico Environment Department (the “NMED”) has also proposed similar rules and regulations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.”

We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. In October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells. In addition, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. The protocols also require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our

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ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays.

Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have an adverse impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”

Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Operations by previous owners and operators may not have been conducted in compliance with applicable rules and regulations, and materials from these operations may remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental claims or violations associated with the properties we purchase or sell, respectively. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability.

Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us.

We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards.

The ESA was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions.

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As of December 31, 2021, approximately 31% of our Delaware Basin acreage position consisted of federal leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of these federal actions related to the oil and natural gas industry remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted.

Oil and natural gas exploration and production activities on federal lands are also subject to NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements or procedures that may be included in the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability.

We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.”

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.”

Office Location

Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240.

Human Capital

At December 31, 2021, we had 286 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for

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company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities.

Employee Recruiting, Retention and Professional Development

We promote inclusion throughout our organization. We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including, but not limited to, discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status.

Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders.

We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2020, for example, our employees completed approximately 15,000 hours of continuing education and study. We also have a formal leadership program that fosters the development and growth of many of our staff with regular meetings and opportunities to enhance their leadership skills.

Proactive Safety Culture

We are proud to have a company culture that emphasizes safety throughout our operations. Between 2017 and 2021, we estimate our employees have worked approximately 2.7 million combined hours without experiencing a single lost time incident. We attribute much of that to the efforts of our Health, Safety and Environmental (“HSE”) group and of the experienced field and office staff involved in our drilling, completion, production and midstream operations to proactively minimize safety risks and address any potential areas of concern.

We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts.

Available Information

Our Internet website address is www.matadorresources.com. We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only.

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Item 1A. Risk Factors.

Summary of Risk Factors

The following is a summary of some of the risks and uncertainties that could materially adversely affect our business, financial condition and results of operations. You should read this summary together with the more detailed risk factors contained below.

Risks Related to our Financial Condition

•Our success is dependent on the prices of oil and natural gas, the volatility of which may adversely affect our financial condition.

•We face numerous risks related to the COVID-19 global pandemic, including its impact on global oil demand.

•Our business requires substantial capital expenditures that may exceed our cash flows from operations and potential borrowings.

•Our oil and natural gas reserves are estimated and may not reflect the actual volumes we will recover, and we may be required to write down the carrying value of our proved properties under accounting rules.

•Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows.

•Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses.

•An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our financial condition.

•A component of our growth may come through acquisitions, which we may be unable to complete or which may require us to incur certain liabilities, risks or title deficiencies.

•Our ability to complete dispositions of assets may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters.

Risks Related to our Liquidity

•We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may incur additional indebtedness, which could reduce our financial flexibility.

•The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility.

•The terms of the agreements governing our indebtedness impose significant operating and financial restrictions.

•Our credit rating may be downgraded, which could reduce our financial flexibility and increase interest expense.

•The payment of dividends will be at the discretion of our Board of Directors and subject to numerous factors, and we do not presently intend to repurchase any shares of our common stock.

Risks Related to our Operations

•Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational, geological and financial risk, and insurance against all such risks is not available to us.

•Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.

•There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques in order to maximize our rate of return, and multi-well pad drilling may result in volatility in our operating results.

•Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions of other operators.

•The unavailability or high cost of equipment and services, supplies and personnel could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis.

•We may be unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules.

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•Regulatory changes could prevent our ability to continue to pool wells in the manner we have been.

•Midstream projects are subject to risks of construction delays and cost over-runs.

•Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties and lease expirations that could materially alter our plans.

Risks Related to Third Parties

•We depend upon several significant purchasers for the sale of most of our production, and financial difficulties encountered by such purchasers, other operators or third parties could decrease our cash flows from operations.

•The marketability of our production is dependent upon gathering, processing and transportation facilities.

•We conduct a portion of our operations through joint ventures, including San Mateo, which subjects us to certain risks.

•Because of the natural decline in production in the regions of San Mateo’s midstream operations, San Mateo’s long-term success depends on its ability to obtain new sources of products.

•We have entered into certain long-term contracts that require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput.

•Competition in our industry is intense, making it more difficult for us to acquire properties, market production, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources.

•We have limited control over activities on properties we do not operate.

Risks Related to Laws and Regulations

•As of December 31, 2021, approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to various requirements and regulations.

•We are subject to government regulation, including environmental laws, which could require significant expenditures.

•We are subject to tax laws, and changes thereto could eliminate or reduced certain federal income tax deductions or net operating loss carryforwards currently available.

•Legislative and regulatory initiatives relating to hydraulic fracturing, induced seismicity, emissions and climate change could result in increased costs, operating restrictions or delays.

•We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations, and the rates of our regulated assets are subject to oversight by regulators, which could adversely affect our revenues.

•Derivatives legislation adopted by Congress could limit our ability to hedge commodity price risks.

Risks Relating to Our Common Stock

•The price of our common stock is volatile and may fluctuate substantially in the future.

•Conservation measures and a negative shift in market perception towards the oil and natural gas industry could adversely affect our stock price.

•Our directors and executive officers own a significant percentage of our equity, which could give them influence in transactions and other matters, and their interests could differ from other shareholders.

•Our Board can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of the Company more difficult even if it might benefit our shareholders.

General Risk Factors

•We may have difficulty managing growth in our business.

•Our success depends on our ability to retain our key personnel.

•If we fail to maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

•A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss.

•Our governing documents and Texas law may have anti-takeover effects that could prevent a change in control.

•We operate in a litigious environment and may be involved in legal proceedings that could have an adverse effect on our results of operations and financial condition.

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Risks Related to our Financial Condition

Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.

The prices we receive for the oil and natural gas we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. For the year ended December 31, 2021, oil prices averaged $68.11 per Bbl, as compared to $39.34 per Bbl in 2020, ranging from a low of $47.62 per Bbl at the start of the year to a high of $84.65 per Bbl in October, based upon the WTI oil futures contract price for the earliest delivery date. For the year ended December 31, 2021, natural gas prices averaged $3.71 per MMBtu, as compared to $2.13 per MMbtu in 2020, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2021, natural gas prices ranged from a low of $2.45 per MMBtu in January to a high of $6.31 per MMBtu in October before finishing the year at $3.73 per MMBtu.

The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following:

•the domestic and foreign supply of, and demand for, oil and natural gas;

•the actions of OPEC+ and state-controlled oil companies relating to oil price and production controls;

•the prices and availability of competitors’ supplies of oil and natural gas;

•the price and quantity of foreign imports;

•the impact of U.S. dollar exchange rates;

•domestic and foreign governmental regulations and taxes;

•speculative trading of oil and natural gas futures contracts;

•the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water;

•the availability of refining capacity;

•the prices and availability of alternative fuel sources;

•weather conditions and natural disasters;

•political conditions in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China;

•domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19;

•the continued threat of terrorism and the impact of military action and civil unrest;

•public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities;

•the level of global oil and natural gas inventories and exploration and production activity;

•the impact of energy conservation efforts;

•technological advances affecting energy consumption; and

•overall worldwide economic conditions.

These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil and natural gas prices do not necessarily fluctuate in direct relation to each other.

Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil or natural gas prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or cease or delay further expansion of our

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midstream projects, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months.

We face numerous risks related to the COVID-19 global pandemic, which has had and is likely to continue to have a material adverse effect on our business, financial condition, results of operations and cash flows.

Since the beginning of 2020, the COVID-19 pandemic has spread across the globe and disrupted economies and industries around the world, including the exploration and production and midstream businesses. The rapid spread of COVID-19 has led to the implementation of various responses, including federal, state and local government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel and other public health and safety measures, nearly all of which materially reduced global demand for crude oil. The extent to which COVID-19 will continue to affect our business, financial condition, results of operations and cash flows and the demand for our production will depend on future developments, which are highly uncertain and cannot be predicted, including the duration or any recurrence of the outbreak and responsive measures, additional or modified government actions, new information that may emerge concerning the severity of COVID-19 and the effectiveness of vaccines and other actions taken to contain COVID-19 or treat its impact now or in the future, among others.

Some impacts of the COVID-19 pandemic that could have an adverse effect on our business, financial condition, results of operations and cash flows include:

•significantly reduced prices for our oil production, resulting from a world-wide decrease in demand for hydrocarbons and a resulting oversupply of existing production;

•further decreases in the demand for our oil production, resulting from significantly decreased levels of global, regional and local travel as a result, in part, of federal, state and local government-imposed quarantines, including shelter-in-place mandates, enacted to slow the spread of COVID-19;

•increased likelihood that we may, either voluntarily or as a result of third-party and regulatory mandates, curtail or shut in production, resulting from depressed oil prices, lack of storage and other market or political forces;

•significant decreases in the volumes of oil, natural gas and produced water that are transported, gathered, processed or disposed of by San Mateo due to curtailed or shut-in production by Matador or other of San Mateo’s customers;

•increased costs associated with, or actual unavailability of, facilities for the storage of oil, natural gas and NGL production in the markets in which we operate;

•increased operational difficulties associated with the delivery of oil, natural gas and NGLs to end-markets, resulting from pipeline and storage constraints;

•the potential for the operations of the Black River Processing Plant and other critical midstream infrastructure to be adversely impacted by outbreaks of COVID-19 among the relevant workforce;

•the potential for forced curtailment of oil and natural gas production by state governmental agencies, resulting in a need to significantly curtail or shut in our production;

•the potential for loss of leasehold interests due to the failure to produce oil and natural gas in paying quantities as a result of significantly lower commodity prices, voluntary or forced curtailments or other factors related to the misalignment of supply and demand, and the potential to incur significant costs associated with litigation related to the foregoing;

•increased third-party credit risk, including the risk that counterparties may not accept the delivery of our oil, natural gas and NGL production, resulting from adverse market conditions, a lack of access to capital and storage or the failure of certain of our counterparties to continue as going concerns;

•increased likelihood that counterparties to our existing agreements may seek to invoke force majeure provisions to avoid the performance of contractual obligations, resulting from significantly adverse market conditions;

•the potential impact for delays in construction or increased costs related to midstream construction projects;

•increased costs, staffing requirements and difficulties sourcing oilfield services related to social distancing measures implemented in connection with federal, state or local government and voluntarily imposed quarantines; and

•increased legal and operational costs related to compliance with significant changes in federal, state and local laws and regulations.

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The COVID-19 outbreak continues to evolve, and the extent to which the outbreak may impact our business, financial condition, results of operations and cash flows will depend highly on future developments, which are very uncertain and cannot be predicted. Additionally, the extent and duration of the impact of the COVID-19 pandemic on our stock price and that of our peer companies is uncertain and may make us look less attractive to investors. As a result, there may be a less active trading market for our common stock, our stock price may be more volatile and our ability to raise capital could be impaired.

Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth.

Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings, under our Credit Agreement, the San Mateo Credit Facility or otherwise, may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable.

Our cash flows from operations and access to capital are subject to a number of variables, including:

•our estimated proved oil and natural gas reserves;

•the amount of oil and natural gas we produce;

•the prices at which we sell our production;

•the costs of developing and producing our oil and natural gas reserves;

•the costs of constructing, operating and maintaining our midstream facilities;

•our ability to attract third-party customers for our midstream services;

•our ability to acquire, locate and produce new reserves;

•the ability and willingness of banks to lend to us; and

•our ability to access the equity and debt capital markets.

In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, the outbreak of contagious or pandemic diseases, financial market disruptions, general economic recessions, oil and natural gas industry recessions, oil and gas company bankruptcies, accounting scandals, overstated reserves estimates by public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.

If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain opportunities. Alternatively, to fund acquisitions, increase our rate of growth, expand our midstream operations, develop our properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets, oil and natural gas producing assets or leasehold interests, the sale or joint venture of oil and natural gas mineral interests, the borrowing of funds or otherwise to meet any increase in capital spending. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected.

Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to,

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among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of:

•the quality and quantity of available data;

•the interpretation of that data;

•the judgment of the persons preparing the estimate; and

•the accuracy of the assumptions used.

The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of certain of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance from our estimates could materially affect the quantities and present value of our reserves.

The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

It should not be assumed that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as:

•actual prices we receive for oil and natural gas;

•actual costs and timing of development and production expenditures;

•the amount and timing of actual production; and

•changes in governmental regulations or taxation.

In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general.

Approximately 44% of our total proved reserves at December 31, 2021 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.

At December 31, 2021, approximately 40% of our total proved reserves were undeveloped and approximately 4% of our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced, or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within five years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows.

The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing on developing our assets in the Delaware Basin, an area with intense competition and

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industry activity. As a result of this activity, we may have difficulty growing our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected.

We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.

There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining, as occurred in 2020. In addition, non-cash write-downs may occur if we have:

•downward adjustments to our estimated proved reserves;

•increases in our estimates of development costs; or

•deterioration in our exploration and development results.

We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock.

Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses.

To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option, which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or NGL prices rise above the maximum price established by the call option or swap as applicable, and may offer protection if prices fall below the minimum price established by the put option or swap, as applicable, only to the extent of the volumes then hedged.

In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions.

Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2021.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.

The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the

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price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows.

Over the past several years, these oil and natural gas basis differentials were volatile and widened at various times. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—General Outlook and Trends” for additional information regarding the differentials. These wider oil and natural gas basis differentials were largely attributable to industry concerns regarding the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGL production in the Delaware Basin. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected.

Although the completion of additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets improved these price differentials in 2020 and 2021, these price differentials could turn negative and widen again in future periods. Should we experience future periods of negative pricing for natural gas as we did at certain times in 2020, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. We have limited oil basis hedges in place to mitigate our exposure to oil price differentials during 2022, and we have no derivative contracts in place to mitigate our exposure to natural gas price differentials.

A component of our growth may come through acquisitions, and our failure to identify or complete future acquisitions successfully could reduce our earnings and hamper our growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties, our earnings could be reduced and our growth could be restricted.

In addition, we may be unable to successfully integrate potential acquisitions into our existing operations. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations and could negatively impact our results of operations and growth potential. Members of our senior management team may be required to devote considerable amounts of time to the integration process, which will decrease the time they will have to manage our business.

Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods.

We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage, the borrowing of funds or otherwise. Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests.

We may purchase oil and natural gas properties or midstream assets with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations.

Before acquiring oil and natural gas properties or midstream assets, we assess the potential reserves, future oil and natural gas prices, operating costs, potential environmental liabilities, condition of the assets, customer contracts and other factors relating to the properties or assets, as applicable. However, our review process is complex and involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties or assets we buy. We may not become sufficiently familiar with the properties or assets to assess fully their deficiencies and capabilities. We may not perform inspections on every well, property or asset, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties or assets we acquire. If we acquire properties or assets with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities.

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We may incur losses or costs as a result of title deficiencies in the properties in which we invest.

If an examination of the title history of a property that we have purchased reveals oil and natural gas leases or mineral interests have been purchased in error from a person who is not the owner of such interests or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease or mineral interest, as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect, would be lost.

It is not our practice in all acquisitions of oil and natural gas leases or mineral interests, or undivided interests in such interests, to undergo the expense of retaining lawyers to examine the title to the interest. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas brokers and/or landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease or mineral interest.

Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such title review and curative work entails expense, which may be significant and difficult to accurately predict. Our failure to cure any title defects may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights or mineral interests in properties in which we hold an interest, we will suffer a financial loss that could adversely affect our financial condition, results of operations and cash flows.

Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters.

From time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the identification of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to us.

Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

Risks Related to our Liquidity

We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, cease the payment of any dividends to our shareholders, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any

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debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations.

We may incur additional indebtedness, which could reduce our financial flexibility, increase interest expense and adversely impact our operations and our unit costs.

As of February 22, 2022, the maximum facility amount under the Credit Agreement was $1.50 billion, the borrowing base was $1.35 billion and our elected borrowing commitment was $700.0 million. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment (subject to compliance with the covenants noted below). At February 22, 2022, we had available borrowing capacity of approximately $554.2 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a borrowing base that was less than our borrowings under the Credit Agreement, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments. The Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75.0 million of cash or cash equivalents), divided by a rolling four quarter EBITDA calculation, of 3.50 or less and a current ratio, which is defined as (x) consolidated current assets plus the unused availability under the Credit Agreement divided by (y) consolidated current liabilities less current maturities under the Credit Agreement, of equal to or greater than 1.0.

As of February 22, 2022, the facility amount under the San Mateo Credit Facility was $450.0 million, and San Mateo had available borrowing capacity of approximately $56.0 million (after giving effect to outstanding letters of credit and subject to San Mateo’s compliance with the covenants noted below). The San Mateo Credit Facility includes an accordion feature, which could expand the commitments of the lenders to up to $700.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. In addition to these restrictions, the San Mateo Credit Facility also contains covenants restricting San Mateo’s ability to incur additional indebtedness, sell assets, pay dividends and make certain investments.

In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement and the San Mateo Credit Facility), we may incur significant amounts of additional indebtedness, including under our Credit Agreement and the San Mateo Credit Facility, through the issuance of additional notes or otherwise, in order to develop our properties, fund acquisitions or invest in certain opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly.

A high level of indebtedness could affect our operations in several ways, including the following:

•requiring a significant portion of our cash flows to be used for servicing our indebtedness;

•increasing our vulnerability to general adverse economic and industry conditions;

•placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing;

•restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and

•increasing the risk that we may default on our debt obligations.

The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility.

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year,

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respectively. We and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 22, 2022, our borrowing base was $1.35 billion, our elected borrowing commitment was $700.0 million, the maximum facility amount under the Credit Agreement was $1.50 billion and we had $100.0 million in outstanding borrowings under, and approximately $45.8 million in outstanding letters of credit issued pursuant to, the Credit Agreement. At February 28, 2022, we had repaid an additional $25.0 million, resulting in $75.0 million in borrowings outstanding under the Credit Agreement. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment (subject to compliance with the covenant noted above). We could be required to repay a portion of any outstanding debt under the Credit Agreement to the extent that, after a redetermination, our outstanding borrowings at such time exceeded the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder, requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results.

Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement and the San Mateo Credit Facility. Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50%, and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement), plus 1.00%, plus, in each case, an amount ranging from 0.75% to 1.75% per annum depending on the level of borrowings under the Credit Agreement. If we borrow funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the reserve adjusted LIBOR rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.75% to 2.75% per annum depending on the level of borrowings under the Credit Agreement. If we have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.00% plus, in each case, an amount ranging from 1.00% to 2.00% per annum depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an amount ranging from 2.00% to 3.00% per annum depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition.

As noted above, under the Credit Agreement and the San Mateo Credit Facility, borrowings in the form of Eurodollar loans currently accrue interest based on LIBOR. The use of LIBOR as a global reference rate is expected to be discontinued. Each of the Credit Agreement and the San Mateo Credit Facility specify that the use of LIBOR as a global reference rate will, upon the occurrence of certain events, transition to a rate based on the Secured Overnight Financing Rate (“SOFR”) plus a credit spread adjustment. As a result, the interest rate for borrowings under the Credit Agreement and the San Mateo Credit Facility may be higher than an interest rate based solely on LIBOR. Each of the Credit Agreement and the San Mateo Credit Facility also specify that in the event that LIBOR and SOFR cannot be determined or other conditions exist with respect to LIBOR and SOFR, a replacement interest rate that gives due consideration to the then-prevailing market convention for determining a rate of interest for syndicated loans in the United States at such time may be established by the respective administrative agents, in consultation with us. If such an event occurs and we are unable to agree upon a replacement interest rate with our respective administrative agents, we could be unable to make borrowings in the form of Eurodollar loans and would have to borrow funds at the higher base rate, which could increase our cost of capital. Furthermore, the overall financial market may be disrupted as a result of the phase-out or replacement of LIBOR or the use of SOFR as a replacement for LIBOR. An increase in our cost of capital or a disruption in the financial market could have an adverse effect on our business and financial condition.

The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions.

Our Credit Agreement, the San Mateo Credit Facility and the indenture governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to:

•incur or guarantee additional debt or issue certain types of preferred stock;

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•pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;

•transfer or sell assets;

•make certain investments;

•create certain liens;

•enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indenture) to us;

•consolidate, merge or transfer all or substantially all of our assets;

•engage in transactions with affiliates; and

•create unrestricted subsidiaries.

A breach of any of these covenants could result in an event of default under our Credit Agreement, the San Mateo Credit Facility and the indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less and a current ratio, which is defined as current assets plus the unused availability under the Credit Agreement, divided by current liabilities, of equal to or greater than 1.0. Low oil and natural gas prices or a decline in our oil or natural gas production may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with this covenant.

Similarly, the San Mateo Credit Facility requires San Mateo to meet a debt to EBITDA ratio, which is defined as consolidated total funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense, of 2.50 or more. Lower revenues as a result of less volumes than anticipated, or otherwise, or an increase in interest rates may adversely impact San Mateo’s EBITDA and interest expense, and therefore San Mateo’s ability to comply with these covenants. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility.

Upon the occurrence of an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement, the San Mateo Credit Facility or the indenture governing our outstanding senior notes is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

Our credit rating may be downgraded, which could reduce our financial flexibility, increase interest expense and adversely impact our operations.

In March 2020, our corporate credit rating from S&P Global Ratings was downgraded from “B+” to “B-” and our corporate credit rating from Moody’s Investors Service was downgraded from “B1” to “B3.” The downgrades resulted in significant part due to the sudden decline in oil prices in early 2020. Moody’s Investor Services subsequently upgraded our corporate credit rating to “B2” in July 2020 and to “B1” in September 2021. S&P Global Ratings upgraded our corporate credit rating to “B” in June 2021 and “B+” in January 2022. In September 2021, Fitch Ratings assigned us a corporate credit rating of “B+.” As of February 22, 2022, our corporate credit ratings from S&P Global Ratings, Moody’s Investors Service and Fitch Ratings remained “B+,” “B1” and “B+,” respectively. We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future.

Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, additional letters of credit or other credit support we may be required to provide to counterparties, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected.

The payment of dividends will be at the discretion of our Board of Directors and subject to numerous factors, and we do not presently intend to repurchase any shares of our common stock.

Our Board of Directors declared a quarterly dividend of $0.025 per share of common stock in each of the first three quarters of 2021 and, in October 2021, the Board amended our dividend policy to increase the quarterly dividend and declared a

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quarterly cash dividend of $0.05 per share of common stock. We intend to continue to pay a quarterly dividend in the future pursuant to a dividend policy adopted by our Board of Directors. However, the payment and amount of future dividend payments, if any, are subject to declaration by our Board of Directors. Such payments will depend on, among other things, our available cash, earnings, financial condition, capital requirements, level of indebtedness, stock price, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds, and, if we experience substantial losses, such funds may not be available.

We do not presently intend to repurchase any shares of our common stock. Certain covenants in our Credit Agreement and the indenture governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. We are under no obligation to make dividend payments on our common stock and may cease such payments at any time in the future. Any elimination of or downward revision in our dividend payout could have a material adverse effect on our stock price.

Risks Related to our Operations

Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational and financial risk, with many uncertainties that could adversely affect our business.

Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation and approvals before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells may be exceeded and such costs can increase significantly due to various complications that may arise during drilling, completion and operation. Before a well is spud, we may incur significant geological, geophysical and land costs, including seismic acquisition costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells could bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly.

If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate in wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following:

•general economic and industry conditions, including the prices received for oil and natural gas;

•shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel;

•potential drainage of oil and natural gas from our properties by operations on adjacent properties;

•the existence or magnitude of faults or unanticipated geological features;

•loss of or damage to oilfield development and service tools;

•accidents, equipment failures or mechanical problems;

•title defects of the underlying properties;

•increases in severance taxes;

•adverse weather conditions that delay drilling activities or cause producing wells to be shut in;

•domestic and foreign governmental regulations; and

•proximity to and capacity of gathering, processing, transportation and disposal facilities.     

Furthermore, our exploration and production operations involve using some of the latest drilling and completion techniques developed by us, other operators and service providers. Risks that we face while drilling and completing horizontal wells include, but are not limited to, the following:

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•landing our wellbore in the desired drilling zone;

•staying in the desired drilling zone while drilling horizontally through the formation;

•running our casing the entire length of the wellbore;

•fracture stimulating the planned number of stages;

•drilling out the plugs between stages following hydraulic fracturing operations; and

•being able to run tools and other equipment consistently through the horizontal wellbore.

Each of these risks is magnified in wells with longer laterals. In 2021, 98% of the operated wells we turned to sales had lateral lengths of two miles or greater. In 2022, we anticipate that 90% of the operated wells we turn to sales should have lateral lengths of two miles or greater. If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected.

Our operations are subject to operational hazards and risks, which could result in significant damages and the loss of revenue.

There are numerous operational hazards inherent in oil and natural gas exploration, development, production, gathering, transportation and processing, including:

•natural disasters;

•adverse weather conditions;

•domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19;

•loss of drilling fluid circulation;

•blowouts where oil or natural gas flows uncontrolled at a wellhead;

•cratering or collapse of the formation;

•pipe or cement leaks, failures or casing collapses;

•damage to pipelines, processing plants and disposal wells and associated facilities;

•fires or explosions;

•releases of hazardous substances or other waste materials that cause environmental damage;

•pressures or irregularities in formations; and

•equipment failures or accidents.

In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.

Furthermore, our operations may be subject to curtailment due to seismic events. In 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. The protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity to the seismic event. If a seismic event were to occur in the area of our operations, the salt water disposal wells that we deliver to or operate may be shut in or curtailed, which may result in increased expenses or the curtailment of our oil and natural gas production. In addition, if such a seismic event occurred in the area of San Mateo’s operations, San Mateo may be required to shut in or curtail the volumes disposed in its salt water disposal wells. Any such events could adversely impact our and San Mateo’s revenues and cash flows.

There are also significant risks associated with the operation of cryogenic natural gas processing plants such as the Black River Processing Plant owned by San Mateo and operated by us. Natural gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of the Black River Processing Plant could result in an explosion or the discharge of toxic gases, which could result in significant damage claims, interrupt a revenue source and prevent us from processing some or all of the natural gas produced from our wells or third-party wells located in nearby asset areas.

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Furthermore, if we were unable to process such natural gas, we may be forced to flare natural gas from, or shut in, the affected wells for an indefinite period of time.

In addition, San Mateo’s gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants, salt water disposal wells and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if San Mateo’s costs to access and transport on these third-party pipelines significantly increase, its profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport, process or dispose of product, or if the volumes San Mateo gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flows could be adversely affected.

Insurance against all operational risks is not available to us.

Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would have otherwise obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.

Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. In recent years, the Delaware Basin has become an area of increasing focus for us, and approximately 93% of our total oil and natural gas production for 2021 was attributable to our properties in the Delaware Basin. Since 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin. We expect that substantially all of our capital expenditures in 2022 will continue to be in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities.

The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our oil and natural gas production due to significant competition for access to gathering systems, pipelines, processing and refinery facilities and oil, condensate and produced water trucking operations. Due to the concentration of our operations, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance. Due to our concentration of properties in the Delaware Basin, we are also particularly exposed to any differential between benchmark prices of oil and natural gas and the wellhead price we receive for our production. See “—Risks Related to our Financial Condition—An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.”

Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, in recent years, including in February 2021, the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, weather conditions and freezing temperatures have resulted in shut ins of producing wells, power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. Certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather.

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Similarly, certain areas of the Eagle Ford shale play are prone to severe tropical weather, such as Hurricane Harvey in August 2017, which caused many operators to shut in production. We experienced minor operational interruptions in our central and eastern Eagle Ford operations as a result of Hurricane Harvey, although future storms might cause more severe damage and interruptions or disrupt our ability to market production from our operating areas, including the Eagle Ford shale and the Delaware Basin.

Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our financial condition, results of operations and cash flows.

There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques in order to maximize our rate of return, cash flow from operations and shareholder value.

As we accumulate and process geological and production data, we attempt to create a development plan, including well spacing and completion design, that maximizes our rate of return, cash flow from operations and shareholder value. Due to many factors, however, including some beyond our control, there is no guarantee that we will be able to find the optimal plan. Future drilling and completion efforts may impact production from existing wells, and parent-child well effects may impact future well productivity as a result of timing, spacing proximity or other factors. If we are unable to design and implement an effective spacing, drilling and completions strategy, it may have a material adverse effect on our financial condition, results of operations and cash flows.

Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own.

Certain of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.

Multi-well pad drilling may result in volatility in our operating results.

We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not produced until other wells being drilled on the pad at the same time are drilled and completed, multi-well pad drilling delays the commencement of production from wells drilled on a given pad, which may cause volatility in our operating results. In addition, problems affecting one well could adversely affect production from other wells on the same pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production. Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity.

The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Shortages or the high cost of drilling rigs, completion equipment and services, drill pipe, casing and other tubular goods, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States or a particular operating area increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, drill pipe, casing and other tubular goods, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling or completion activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us. Further, supply chain disruptions being experienced throughout the United States may

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limit our ability to procure the necessary products and services for drilling and completing wells, which could cause delays in our drilling and completion activities which, in turn, could adversely affect our business, financial condition, results of operations and cash flows.

In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business, financial condition, results of operations and cash flows.

If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.

We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as (i) hydraulic fracturing, including, but not limited to, the use of fresh water in such operations, or (ii) disposal of waste, including, but not limited to, the disposal of produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have an adverse effect on our business, financial condition, results of operations and cash flows.

If regulatory changes prevent our ability to continue to pool wells in the manner we have been, it could have a material adverse impact on our future production results.

In Texas, allocation wells allow an operator to drill a horizontal well under two or more leaseholds that are not pooled or across multiple existing pooled units. In New Mexico, operators are able to pool multiple spacing units in order to drill a single horizontal well across several leaseholds. We are active in drilling and producing both allocation wells in Texas and pooled spacing unit wells in New Mexico. If there are regulatory changes with regard to such wells, the applicable state agency denies or significantly delays the permitting of such wells, legislation is enacted that negatively impacts the current process under which such wells are permitted or litigation challenges the regulatory schemes pursuant to which such wells are permitted, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production.

Construction of midstream projects subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations, cash flows and liquidity.

From time-to-time, we, through San Mateo or otherwise, plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of oil, natural gas and produced water gathering or transportation systems, construction of natural gas processing plants, drilling of commercial salt water disposal wells and construction of related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, government and regulatory approval, compliance with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, results of operations, liquidity and financial condition. The construction of produced water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.

Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas prices, assessment of

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risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital, approval by regulators, lease terms, seasonal conditions and the actions of other operators. Additionally, as lateral lengths greater than one mile have become increasingly common in the Delaware Basin, we may have to cooperate with other operators to ensure that our acreage is included in drilling units or otherwise developed. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of these federal actions related to the natural gas industry remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our drilling locations on federal lands may not be drilled as scheduled. The final determination on whether to drill any of the identified locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows.

Certain of our unproved and unevaluated acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

At December 31, 2021, we had leasehold interests in approximately 25,100 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to 2027. Unless we establish and maintain production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases, or top leases, may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows.

The 2-D and 3-D seismic data and other advanced technologies we use cannot eliminate exploration risk, which could limit our ability to replace and grow our reserves and materially and adversely affect our results of operations and cash flows.

We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, the acquisition of seismic and geological data can be expensive and require the incurrence of various risks and liabilities, and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration and development activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows.

Risks Related to Third Parties

Financial difficulties encountered by our oil and natural gas purchasers, third-party operators or other third parties could decrease our cash flows from operations and adversely affect the exploration and development of our prospects and assets.

We derive most of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the years ended December 31, 2021, 2020 and 2019, we had three, two and two significant purchasers, respectively, that collectively accounted for approximately 72%, 65% and 67%, respectively, of our total oil, natural gas and NGL revenues. We cannot ensure that we will continue to have ready access to suitable markets for our future production. If we lost one or more of these customers and were unable to sell our production to other customers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. Furthermore, we cannot predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by financial problems encountered by them could have an immediate negative effect on our results of operations and cash flows.

In addition to credit risk related to purchasers of our production, we also face credit risk through receivables from joint interest owners on properties we operate and from San Mateo’s customers. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We are generally unable to control which co-owners participate in our wells. Liquidity and cash flow problems encountered by our joint interest owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our joint interest owners may be unwilling or unable to pay their

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share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be negatively affected.

The marketability of our production is dependent upon oil, natural gas and NGL gathering, processing and transportation facilities, and the unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements could have a material adverse effect on our revenue.

The unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production from our wells. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include those of San Mateo, as well as other systems and operations owned and operated by third parties. The continuing operation of, and our continuing access to, third-party systems and operations is outside our control. Regardless of who operates the midstream systems or operations upon which we rely, our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. Furthermore, such facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues.

We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases.

The disruption of our own or third-party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these pipelines significantly increase, our profitability could be reduced. Third parties control when or if their facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production. While we have entered into natural gas processing and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the gathering or processing commitments, as applicable. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2022. If we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We conduct a portion of our operations through joint ventures, which subjects us to additional risks that could have a material adverse effect on the success of these operations, our financial position, results of operations or cash flows.

We own and operate substantially all of our midstream assets in the Delaware Basin through San Mateo, and we have and may continue to enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share a portion of control with unaffiliated third parties. If our joint venture partners do not fulfill their contractual and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of financial commitment or seek third-party capital, which could dilute our ownership in the applicable joint venture. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Furthermore, there can be no assurance that any joint venture will be successful or generate cash flows at the level we have anticipated, or at all. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. We provide management functions for certain joint ventures and may provide such services for future joint venture arrangements, which may require additional time and attention of management or require us to hire or contract additional personnel. Third parties may also seek to hold us liable for a joint venture’s liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our financial condition, results of operations and cash flows.

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Because of the natural decline in production in the regions of San Mateo’s midstream operations, San Mateo’s long-term success depends on its ability to obtain new sources of products, which depends on certain factors beyond San Mateo’s control. Any decrease in supplies to its midstream facilities could adversely affect San Mateo’s business and operating results.

San Mateo’s midstream facilities are, or will be, connected to oil and natural gas wells operated by us or by third parties from which production will naturally decline over time, which means that the cash flows associated with these sources of oil, natural gas, NGLs and produced water will also decline over time. Some of these third parties are not subject to minimum volume commitments. To maintain or increase throughput levels on San Mateo’s gathering systems and the utilization rate at its other midstream facilities, San Mateo must continually obtain new sources of products. San Mateo’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities. San Mateo has no control over the level of activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, San Mateo has no control over producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital.

We have entered into certain long-term contracts that require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and that may limit our ability to use other service providers.

From time to time, we have entered into and may in the future enter into certain oil, natural gas or produced water gathering or transportation agreements, natural gas processing agreements, NGL transportation agreements, produced water disposal agreements or similar commercial arrangements with midstream companies, including San Mateo. Certain of these agreements require us to meet minimum volume commitments, often regardless of actual throughput. Reductions in our drilling activity could result in insufficient production to fulfill our obligations under these agreements. As of December 31, 2021, our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $987.6 million over the terms of the agreements. If we have insufficient production to meet the minimum volume commitments under any of these agreements, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations.

Pursuant to certain of our agreements with midstream companies, we have dedicated our current and future leasehold interests in certain of our asset areas to counterparties. As a result, we will be limited in our ability to use other gathering, processing, disposal and transportation service providers, even if such service providers are able to offer us more favorable pricing or more efficient service.

We do not own all of the land on which our midstream assets are located, which could disrupt our operations.

We do not own all of the land on which our midstream assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs or royalties to retain necessary land access if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land or find alternative locations for our operations at increased costs, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.

Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend in part on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, to market oil and natural gas and to secure trained personnel. Similarly, our midstream business, and particularly the success of San Mateo, depends in part on our ability to compete with other midstream service companies to attract third-party customers to our midstream facilities. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical, technological and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical, technological or personnel resources permit. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may

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force us to implement new technologies at a substantial cost. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we use or that we may implement in the future may become obsolete, and our operations may be adversely affected.

In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired.

To develop our business, we endeavor to use the business relationships of our management, Board of Directors and special Board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies and service companies, including those that supply equipment and other resources that we expect to use in our business, as well as midstream companies and certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur or undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

We have limited control over activities on properties we do not operate.

We are not the operator on some of our properties in Northwest Louisiana, particularly in the Haynesville shale. We also have other non-operated acreage positions in Southeast New Mexico, West Texas and South Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:

•the timing and amount of capital expenditures;

•the operator’s expertise and financial resources;

•the rate of production of reserves, if any;

•approval of other participants in drilling wells; and

•selection and implementation or execution of technology.

In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production.

Risks Related to Laws and Regulations

Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.

At December 31, 2021, Matador held approximately 124,800 net leasehold and mineral acres in the Delaware Basin in Eddy and Lea Counties, New Mexico and in Loving County, Texas, of which approximately 38,600 net acres, or about 31%, were on federal lands administered by the BLM. In addition to permits issued by state and local authorities, oil and natural gas activities on federal lands also require permits from the BLM. Permitting for oil and natural gas activities on federal lands can

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take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In addition, litigation related to leasing and permitting of federal lands could also restrict, delay or limit our ability to conduct operations on our federal leasehold or acquire additional federal leasehold. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of these federal actions remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. At the federal level, various policy makers, regulatory agencies and political candidates, including President Biden, have also proposed restrictions on hydraulic fracturing, including its outright prohibition. It is possible that any such restrictions on hydraulic fracturing may particularly target activity on federal lands. Any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows.

Oil and natural gas exploration and production activities on federal lands are also subject to NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements that may be implemented, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability.

We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.

The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. The change in the presidential administration may also increase the uncertainty with regard to potential changes in these laws, rules and regulations and the enforcement of any new legislation or directives by governmental authorities. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation, gathering and transportation of oil, natural gas and NGLs, gathering and disposal of produced water, environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. If existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations or those of our service providers, such changes may affect the costs that we pay for such services or the results of business. In addition to expenditures required in order for us to comply with such laws and regulations, expenditures required by such laws and regulations could also include payments and fines for:

•personal injuries;

•property damage;

•containment and clean-up of oil, produced water and other spills;

•venting, flaring or other emissions;

•management and disposal of hazardous materials;

•remediation, clean-up costs and natural resource damages; and

•other environmental damages.

We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. The costs of remedying noncompliance may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Laws, rules and regulations protecting the environment have

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changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous and non-hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or our facilities are located, the owners of properties adjacent to or in close proximity to those properties or non-governmental organizations such as environmental groups, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. For example, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. Private parties may also pursue legal actions challenging permitting programs that authorize certain of our operations. For example, it is possible that courts could vacate relevant NWPs as such potential permit coverage relates to activities in the oil and natural gas sector, or the Biden administration could choose to suspend the availability of NWPs in the future, thereby forcing our relevant operations to seek coverage under individual permits under CWA Section 404 (which is a longer and more administratively complex process that is subject to NEPA).

Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Furthermore, we participate in candidate conservation agreements for the lesser prairie-chicken, the sand dune lizard and the Texas hornshell mussel, pursuant to which we are restricted from operating in certain sensitive locations or at certain times. Participation in such agreements or the designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have an adverse impact on our business, financial condition, results of operations and cash flows. See “Business—Regulation.”

We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico.

In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the U.S. federal level. Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. The Build Back Better Act (H.R. 5376) was passed by the U.S. House of Representatives on November 19, 2021 and contains certain U.S. federal income tax changes, including a 15% corporate minimum tax imposed on net taxable income of certain corporations with more than $1 billion in average adjusted financial statement income for the three-year tax period ending with the corporation’s current tax year. The passage of any legislation or any other similar change in U.S. federal income or state tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and NGLs from formations such as the Wolfcamp and Bone Spring plays, the Eagle Ford shale and the Haynesville shale, where we focus our operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or implemented. In past sessions, Congress has considered, but has not passed, legislation to amend the SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Also at the federal level, in March 2015, the BLM issued final

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rules, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water, to regulate hydraulic fracturing on federal and Indian lands. These rules were rescinded by rule in December 2017; however, in January 2018, California and a coalition of environmental groups filed a lawsuit in the Northern District of California to challenge the BLM’s rescission of the rules. The Northern District of California upheld the rescission in 2020, but this decision was then appealed to the Ninth Circuit Court of Appeals. However, in October 2020, the U.S. District Court for the District of Wyoming found that the BLM exceeded its statutory authority and acted arbitrarily in promulgating the 2016 Waste Prevention Rule. The court ordered that the rule be vacated, except for certain severable provisions. This decision has been appealed to the Tenth Circuit Court of Appeals.

Various policymakers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. At various times during his presidential campaign, President Biden indicated support for prohibitions of hydraulic fracturing on federal lands or outright. Any such restrictions on hydraulic fracturing on federal lands could adversely impact our operations in the Delaware Basin, and an outright prohibition would adversely impact essentially all of our operations. In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, in December 2014, New York announced a moratorium on high volume fracturing activities combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing. Certain communities in Colorado have also enacted bans on hydraulic fracturing. These actions are the subject of legal challenges. Texas and New Mexico have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. Recently, bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing activities, including prohibiting the injection of fresh water in such operations. Although such bills have not passed, similar laws, rules, regulations or orders at the local, state or federal level could limit our operations.

The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or BLM, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.

The potential adoption of federal, state and local legislation and regulations intended to address potential induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays.

State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity. When caused by human activity, such events are called “induced seismicity.” Regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells.

While the scientific community and regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity, some state regulatory agencies, including in Texas and New Mexico, have modified their regulations or guidance to mitigate potential causes of induced seismicity. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. See “Business—Regulation— Environmental, Health and Safety Regulation.”

Increased seismicity in areas in which we operate could result in additional regulation and restrictions on our operations and could lead to operational delays or increased operating costs. Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and natural gas activities. We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the

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imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from drilling and production activities could adversely impact our business, cash flows and results of operations and could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays.

Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

We believe it is likely that scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations and litigation that could affect our operations. Our operations result in greenhouse gas emissions. The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. While the United States exited the Paris Agreement in November 2020, effective February 19, 2021, President Biden caused the United States to rejoin the Paris Agreement. In April 2021, President Biden set a new goal for the United States to achieve a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030, and cooperating toward the advancement of the development of alternative sources of energy. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The NMED has also proposed similar rules and regulations. The EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas.

In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects and increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—Risks Related to our Operations—If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.

The adoption of legislation or regulatory programs to reduce greenhouse gas emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory

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programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain family foundations and sovereign wealth, pension and endowment funds, promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Additionally, the threat of climate change has resulted in increasing political risk in the United States as various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed bans of new leases for production of minerals on federal properties and various restrictions on hydraulic fracturing, including its outright prohibition. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders, limiting the issuance of federal drilling permits and other federal approvals. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of these federal actions remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted.

President Biden and the Democratic Party, which now controls Congress, have identified climate change as a priority, and new executive orders, regulatory action and/or legislation targeting greenhouse gas emissions, promoting energy efficiency or the development and consumption of alternative forms of energy, or prohibiting or restricting oil and natural gas development activities in certain areas, have been and likely will be proposed and/or promulgated during the Biden administration. In addition, the Biden administration has already issued multiple executive orders pertaining to environmental regulations and climate change, including the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis and the Executive Order on Tackling the Climate Crisis at Home and Abroad. In the latter executive order, President Biden established climate change as a primary foreign policy and national security consideration, affirmed that achieving net-zero greenhouse gas emissions by or before 2050 is a critical priority, affirmed his administration’s desire to establish the United States as a leader in addressing climate change and generally further integrated climate change and environmental justice considerations into government agencies’ decision-making, among other measures. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of greenhouse gas emissions-related agreements, legislation and measures on our financial performance is highly uncertain because we are unable to predict, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and trade-offs that inevitably occur in connection with such processes.

New regulations on all emissions from our operations could cause us to incur significant costs.

In recent years, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs under the CAA and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA finalized a more stringent National Ambient Air Quality Standard for ozone in October 2015. The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas in which we operate have been classified as “non-attainment” areas, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. To the extent regions reclassified as non-attainment areas under the lower ozone standard have begun implementing new, more stringent regulations, those regulations could also apply to our or San Mateo’s customers’ operations. Generally, it takes states several years to develop compliance plans for their non-attainment areas. In November 2016, the Department of the Interior issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The rules limit routine flaring of natural gas, require the payment of royalties on avoidable natural gas losses and require plans or programs relating to natural gas capture and leak detection and repair. However, in October 2020, the U.S. District Court for the District of Wyoming found that the BLM exceeded its statutory authority and acted arbitrarily in promulgating the 2016 Waste Prevention Rule. The court ordered that the rule be vacated, except for certain severable provisions. This decision has been appealed to the Tenth Circuit Court of Appeals. If not withdrawn or significantly revised, these rules are expected to result in an increase to our operating costs and changes in our operations. In November 2021, the EPA also proposed new NSPS updates and emission guidelines to reduce methane and other pollutants from the oil and gas industry. In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. As a result of this continued regulatory focus, future federal and state

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regulations of the oil and natural gas industry remain a possibility and could result in increased compliance costs for our operations.

We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.

Our pipelines are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. The Rustler Breaks Oil Pipeline System is subject to such rules. PHMSA also recently proposed rulemaking that would expand existing integrity management requirements to natural gas transmission and gathering lines in areas with medium population densities. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.

Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the RRC and the NMOCD could result in substantial expenditures for testing, repairs and replacement. Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial position.

A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by FERC may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under the ICA. San Mateo’s Rustler Breaks Oil Pipeline System, which includes crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains, is subject to FERC jurisdiction. We believe the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and determined on a case-by-case basis. A change in the jurisdictional characterization of our facilities by FERC, the courts or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

The rates of our regulated assets are subject to review and reporting by federal regulators, which could adversely affect our revenues.

The Rustler Breaks Oil Pipeline System transports crude oil in interstate commerce. FERC regulates the rates, terms and conditions of service on pipelines that transport crude oil in interstate commerce. If a party with an economic interest were to file either a complaint against our tariff rates or protest any proposed increases to our tariff rates, or FERC were to initiate an investigation of our rates, then our rates could be subject to detailed review. If any proposed rate increases were found by FERC to be in excess of just and reasonable levels, FERC could order us to reduce our rates and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found by FERC to be in excess of just and reasonable levels, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues and cash flows.

In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on the Rustler Breaks Oil Pipeline System and any other natural gas or crude oil pipeline that is determined to be under the jurisdiction of FERC.

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to approximately $1.3 million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. While the nature of our gathering facilities is such that these facilities have not yet been regulated by FERC, the Rustler Breaks Oil Pipeline System

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does transport crude oil in interstate commerce and, therefore, is subject to FERC regulation. Laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability.

The derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished.

In 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in 2012. However, in 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. In 2016, the CFTC decided to re-propose, rather than finalize, certain regulations, including limitations on speculative futures and swap positions. The CFTC has not acted on the re-proposed position limit regulations. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future.

If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices.

Any of these consequences could have a material adverse effect on our business, financial condition and results of operations.

Risks Relating to Our Common Stock

The price of our common stock has fluctuated substantially and may fluctuate substantially in the future.

Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2021, our stock price fluctuated between a high of $47.23 and a low of $12.02. In addition, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.

Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include:

•our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates;

•quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us;

•changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts;

•declaration of dividends or adjustments to our dividend policy;

•speculation in the press or investment community;

•announcement or consummation of acquisitions, dispositions or joint ventures by us;

•public reaction to our operations or plans, press releases, announcements and filings with the SEC;

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•the publication of research or reports by industry analysts regarding the Company, its competitors or our industry;

•the enactment of federal, state or local laws, rules or regulations that restrict our ability to conduct our operations, such as the Biden Administration Federal Lease Orders;

•sales of our common stock by the Company, directors, officers or other shareholders, or the perception that such sales may occur;

•general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and NGLs;

•domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19;

•the realization of any of the risk factors presented in this Annual Report;

•the recruitment or departure of key personnel;

•commencement of, involvement in or unfavorable resolution of litigation;

•the success of our exploration and development operations, our midstream business (including San Mateo) and the marketing of any oil, natural gas and NGLs we produce;

•changes in market valuations of companies similar to ours; and

•domestic and international economic, legal and regulatory factors unrelated to our performance.

Conservation measures and a negative shift in market perception towards the oil and natural gas industry could adversely affect demand for oil and natural gas and our stock price.

Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. In recent years prior to 2021, equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, sovereign wealth funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Other significant investors have published ESG disclosure standards that companies in which they invest are expected to adopt or follow. Furthermore, fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. Such developments could result in downward pressure on the stock prices of oil and natural gas companies, including ours.

Certain other stakeholders have pressured commercial and investment banks and other capital providers to stop funding oil and natural gas projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially those primarily focused in the shale plays. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our stock price may be adversely affected.

Future sales of shares of our common stock by existing shareholders and future offerings of our common stock by us could depress the price of our common stock.

The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of equity or debt securities convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders, including directors or officers, sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock.

We may also sell or issue additional shares of common stock or equity or debt securities convertible into common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock.

Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and the interests of our directors and executive officers could differ from other shareholders.

As of February 22, 2022, our directors and executive officers beneficially owned approximately 6.5% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder

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vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions.

Our Board can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of the Company more difficult even if it might benefit our shareholders.

Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock.

Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of control might benefit our shareholders.

General Risk Factors

We may have difficulty managing growth in our business, which could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion.

Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including our midstream business, through San Mateo or otherwise, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion.

Our success depends, to a large extent, on our ability to retain our key personnel, including our chairman and chief executive officer, management and technical team, the members of our Board and our special Board advisors, and the loss of any key personnel, Board member or special Board advisor could disrupt our business operations.

Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions and areas for further development. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected.

In addition, our Board of Directors consults regularly with our special Board advisors regarding our business and the evaluation, exploration, engineering and development of our prospects and properties. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected.

If we fail to maintain effective internal control over financial reporting in the future, our ability to accurately report our financial results could be adversely affected.

As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is difficult and costly and occupies a significant amount of time of our Board of Directors and management.

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Pursuant to the Sarbanes-Oxley Act, we are required to maintain internal control over financial reporting. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Our management does not expect that our internal controls and disclosure controls will prevent all possible error or all fraud. Any failure to maintain effective controls could result in material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price.

A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss.

The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development, production, gathering, processing and financial activities. We depend on digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production, gathering, processing and disposal operations, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. Industrial control systems, such as our supervisory control and data acquisition (SCADA) systems, control important processes and facilities that are critical to our operations. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches, phishing schemes or attacks, possible consequences include financial losses and the inability to engage in any of the aforementioned activities. Any such consequence could have a material adverse effect on our business.

While we have experienced certain phishing schemes and efforts to access our network, we have not experienced any material losses due to cyber incidents. However, we may suffer such losses in the future. If our systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to proprietary information, which could lead to data corruption, communication interruption, exposure of our or third parties’ confidential or proprietary information, operational disruptions or financial loss. As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and enhance our protective systems or to investigate and remediate any vulnerabilities.

Provisions of our certificate of formation, bylaws and Texas law may have anti-takeover effects that could prevent a change in control even if it might be beneficial to our shareholders.

Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include:

•authorization for our Board of Directors to issue preferred stock without shareholder approval;

•a classified Board of Directors so that not all members of our Board of Directors are elected at one time;

•the prohibition of cumulative voting in the election of directors; and

•a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock.

Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board of Directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder.

We operate in a litigious environment and may be involved in legal proceedings that could have an adverse effect on our results of operations and financial condition.

Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

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Item 1B. Unresolved Staff Comments.

Not applicable. 

Item 2. Properties.

See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 4 to the consolidated financial statements in this Annual Report for the future minimum rental payments. Such information is incorporated herein by reference. 

Item 3. Legal Proceedings.

We are party to several legal proceedings encountered in the ordinary course of business. While the ultimate outcome and impact on us cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on our financial condition, results of operations or cash flows.

On November 4, 2019, we received a Notice of Violation and Finding of Violation from the EPA and a Notice of Violation from the NMED alleging violations of the CAA and New Mexico State Implementation Plan at certain of our operated locations in New Mexico. We have provided information to the EPA and NMED and are engaged in discussions regarding a resolution of the alleged violations. We believe it is remote that the resolution of this matter will have a material adverse impact on our financial condition, results of operations or cash flows. Resolution of the matter may result in monetary sanctions of more than $300,000.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

General Market Information

Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock.

On February 22, 2022, we had 118,043,776 shares of common stock outstanding held by approximately 335 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name.

Equity Compensation Plan Information

The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2021.

Equity Compensation Plan Information
Plan Category						Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights						Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights						Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by security holders(1)(2)						2,248,984						$	22.92					1,571,972
Equity compensation plans not approved by security holders						—						—						—
Total						2,248,984						$	22.92					1,571,972

__________________

(1)Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”).

(2)The Matador Resources Company 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”) was adopted by our Board of Directors in April 2019 and approved by our shareholders on June 6, 2019. For a description of our 2019 Incentive Plan, see Note 9 to the consolidated financial statements in this Annual Report.

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Share Performance Graph

The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2016 through December 31, 2021, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed.

This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance.

Comparison of Cumulative Total Return Among

Matador Resources Company, the Russell 2000 Index

and the Russell 2000 Energy Index

 

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Repurchase of Equity by the Company or Affiliates

During the quarter ended December 31, 2021, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.

Period						Total Number of Shares Purchased(1)						Average Price Paid Per Share						Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs						Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs
October 1, 2021 to October 31, 2021						—						$	—					—						—
November 1, 2021 to November 30, 2021						2,051						39.55						—						—
December 1, 2021 to December 31, 2021						4,321						38.26						—						—
Total						6,372						$	38.68					—						—

_________________

(1)The shares were not re-acquired pursuant to any repurchase plan or program. The Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.

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Item 6. Selected Financial Data.

Not applicable. 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the impact of the worldwide spread of COVID-19 on oil and natural gas demand, oil and natural gas prices and our business, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”

For a comparison of our results of operations for the years ended December 31, 2020 and December 31, 2019, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 26, 2021.

Overview

We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations, primarily through San Mateo, in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.

2021 Operational Highlights

We began 2021 operating three drilling rigs in the Delaware Basin, as we continued to focus on the exploration, delineation and development of our Delaware Basin acreage in Lea and Eddy Counties, New Mexico and Loving County, Texas. In March 2021, we added a fourth rig to our operated drilling program, and in August 2021, we began operating a fifth drilling rig on behalf of San Mateo for the purpose of drilling an additional salt water disposal well in the southern part of the Arrowhead asset area in Eddy County, New Mexico (the “Greater Stebbins Area”). In October 2021, following the conclusion of drilling operations on the salt water disposal well, we moved this rig to the Rodney Robinson leasehold in the western portion of the Antelope Ridge asset area in Lea County, New Mexico. We operated five drilling rigs in the Delaware Basin during the remainder of 2021. Despite the addition of the fifth operated drilling rig and the acceleration of 11 Voni well completions forward into the fourth quarter of 2021, we were able to achieve D/C/E capital expenditures for 2021 of $513 million, which was below our original estimated range for 2021 D/C/E capital expenditures of $525 to $575 million as provided on February 23, 2021 and our revised estimated range for 2021 D/C/E capital expenditures of $535 to $565 million as provided on October 26, 2021.

During the year ended December 31, 2021, we completed and began producing oil and natural gas from 47 gross (44.2 net) operated and 50 gross (4.0 net) non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2021, although we did participate in the drilling and completion of seven gross (less than 0.1 net) non-operated Haynesville shale wells that began producing in 2021.

The vast majority of our 2021 capital expenditures was directed to (i) the delineation and development of our leasehold position in the Delaware Basin, (ii) the development of certain midstream assets to support our operations there, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin. Our remaining capital expenditures were primarily directed to the installation of pumping units and other

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facilities on certain of our Eagle Ford shale wells in South Texas and to our participation in several non-operated wells drilled and completed in the Haynesville shale in Northwest Louisiana throughout 2021.

Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, an increase of 15%, as compared to 75,175 BOE per day, including 43,526 Bbl of oil per day and 189.9 MMcf of natural gas per day, for the year ended December 31, 2020. Our average daily oil production in 2021 of 48,876 Bbl of oil per day increased 12% from 43,526 Bbl of oil per day in 2020. This increase in oil production was primarily a result of our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not turned to sales any new operated wells since the second quarter of 2019. Our average daily natural gas production of 223.8 MMcf per day in 2021 increased 18% from 189.9 MMcf per day in 2020. This increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining natural gas production in the Haynesville shale where we had significantly less non-operated activity in 2020 and 2021 as compared to 2019. Oil production comprised 57% of our total production for the year ended December 31, 2021, as compared to 58% in 2020.

For the year ended December 31, 2021, our oil and natural gas revenues were $1.70 billion, an increase of 128% from oil and natural gas revenues of $744.5 million for the year ended December 31, 2020. Our oil revenues increased 102% to $1.21 billion, as compared to $595.5 million for the year ended December 31, 2020. The increase in oil revenues resulted from a significantly higher weighted average realized oil price of $67.58 per Bbl in 2021, as compared to $37.38 per Bbl in 2020, as well as the 12% increase in oil production for the year ended December 31, 2021 noted above. Our natural gas revenues increased 232% to $494.9 million, as compared to $149.0 million for the year ended December 31, 2020. The increase in natural gas revenues resulted from an almost three-fold increase in our weighted average realized natural gas price of $6.06 per Mcf in 2021, as compared to $2.14 per Mcf in 2020, and the 18% increase in our natural gas production noted above.

We reported net income attributable to Matador shareholders of approximately $585.0 million, or $4.91 per diluted common share, on a GAAP basis for the year ended December 31, 2021, as compared to a net loss of $593.2 million, or ($5.11) per diluted common share, for the year ended December 31, 2020. Adjusted EBITDA for the year ended December 31, 2021 was $1.05 billion, as compared to Adjusted EBITDA of $519.3 million for the year ended December 31, 2020. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data—Non-GAAP Financial Measures.”

At December 31, 2021, our estimated total proved oil and natural gas reserves were 323.4 million BOE, including 181.3 million Bbl of oil and 852.5 Bcf of natural gas, with a Standardized Measure of $4.38 billion and a PV-10 of $5.35 billion. At December 31, 2020, our estimated total proved oil and natural gas reserves were 270.3 million BOE, including 159.9 million Bbl of oil and 662.3 Bcf of natural gas, with a Standardized Measure of $1.58 billion and a PV-10 of $1.66 billion. Our estimated total proved reserves of 323.4 million BOE at December 31, 2021 represented a 20% year-over-year increase, as compared to 270.3 million BOE at December 31, 2020. Our estimated proved oil reserves of 181.3 million Bbl at December 31, 2021 increased 13%, as compared to 159.9 million Bbl at December 31, 2020, and our estimated proved natural gas reserves of 852.5 Bcf at December 31, 2021 increased 29%, as compared to 662.3 Bcf at December 31, 2020. Proved oil reserves comprised 56% of our total proved reserves at December 31, 2021, as compared to 59% at December 31, 2020. At December 31, 2021, 60% of our total proved reserves were proved developed reserves, as compared to 46% at December 31, 2020.

Our proved oil and natural gas reserves in the Delaware Basin increased 19% to 312.0 million BOE at December 31, 2021, as compared to 261.9 million BOE at December 31, 2020, primarily as a result of our ongoing delineation and development operations there. At December 31, 2021, approximately 96% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 13% to 177.1 million Bbl at December 31, 2021, as compared to 156.3 million Bbl at December 31, 2020, and our proved natural gas reserves in the Delaware Basin increased 28% to 809.3 Bcf, as compared to 633.5 Bcf at December 31, 2020. Proved oil reserves comprised 57% of our Delaware Basin total proved reserves at December 31, 2021, as compared to 60% at December 31, 2020.

At both December 31, 2021 and December 31, 2020, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business—Estimated Proved Reserves.”

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2021 Midstream Highlights

San Mateo achieved strong operating results in 2021, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes, all as compared to 2020. Volumes for the years ended December 31, 2021 and 2020 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2021 and 2020. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point.

During 2021, San Mateo closed seven new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing, oil gathering and transportation and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. For example, San Mateo was able to keep its gathering, processing and disposal systems operational throughout the historically prolonged cold weather conditions experienced in New Mexico and Texas during Winter Storm Uri in February 2021.

At December 31, 2021, San Mateo’s midstream system included:

•Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico;

•Oil Assets: Three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 90 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and

•Produced Water Assets: 14 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 370,000 Bbl per day and approximately 130 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.

2022 Capital Expenditure Budget

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2022. In the second half of 2021, we added a fifth operated drilling rig in the Delaware Basin to drill a salt water disposal well on behalf of San Mateo. In October 2021, following the conclusion of drilling operations on the salt water disposal well, we began drilling oil and natural gas wells with this rig, and we plan to operate these five contracted drilling rigs in the Delaware Basin throughout 2022. In addition, at February 22, 2022, we had contracted a sixth operated drilling rig to begin drilling operations immediately on recently acquired acreage in western Lea County, New Mexico in our Ranger asset area. We expect to operate this sixth rig on the newly acquired acreage throughout the remainder of 2022. We have built significant optionality into our 2022 drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2022 estimated capital expenditure budget consists of $640.0 to $710.0 million for D/C/E capital expenditures and $50.0 to $60.0 million for midstream capital expenditures, which primarily reflects our proportionate share of San Mateo’s estimated 2022 capital expenditures. Substantially all of these 2022 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2022 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells in 2022, including 90% with anticipated completed lateral lengths of two miles or greater.

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At December 31, 2021, we had $48.1 million in cash (excluding restricted cash) and $554.2 million in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $700.0 million). Excluding any possible significant acquisitions, we expect to fund our 2022 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2022, we expect to fund any such excess capital expenditures through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.

We may divest portions of our non-core assets, particularly in the Haynesville shale and in our South Texas position (as we did in 2020, 2021 and early 2022), as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin, during 2022. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2022 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquisitions of producing properties, acreage and mineral interests and midstream assets for 2022. The aggregate amount of capital we expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital.

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Revenues

The following table summarizes our revenues and production data for the periods indicated.

						Year Ended December 31,
						2021						2020						2019
Operating Data:
Revenues (in thousands):(1)
Oil						$	1,205,608					$	595,507					$	759,811
Natural gas						494,934						148,954						132,514
Total oil and natural gas revenues						1,700,542						744,461						892,325
Third-party midstream services revenues						75,499						64,932						59,110
Sales of purchased natural gas						86,034						41,742						74,769
Lease bonus - mineral acreage						—						4,062						1,711
Realized (loss) gain on derivatives						(220,105)						38,937						9,482
Unrealized gain (loss) on derivatives						21,011						(32,008)						(53,727)
Total revenues						$	1,662,981					$	862,126					$	983,670
Net Production Volumes:(1)
Oil (MBbl)						17,840						15,931						13,984
Natural gas (Bcf)						81.7						69.5						61.1
Total oil equivalent (MBOE)(2)						31,454						27,514						24,164
Average daily production (BOE/d)(2)						86,176						75,175						66,203
Average Sales Prices:
Oil, without realized derivatives (per Bbl)						$	67.58					$	37.38					$	54.34
Oil, with realized derivatives (per Bbl)						$	56.70					$	39.83					$	54.98
Natural gas, without realized derivatives (per Mcf)						$	6.06					$	2.14					$	2.17
Natural gas, with realized derivatives (per Mcf)						$	5.74					$	2.14					$	2.18

________________

(1)We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues.

(2)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Year Ended December 31, 2021 as Compared to Year Ended December 31, 2020

Oil and natural gas revenues. Our oil and natural gas revenues increased $956.1 million, or 128%, to $1.70 billion for the year ended December 31, 2021, as compared to $744.5 million for the year ended December 31, 2020. Our oil revenues increased $610.1 million, or 102%, to $1.21 billion for the year ended December 31, 2021, as compared to $595.5 million for the year ended December 31, 2020. This increase in oil revenues resulted from an 81% increase in the weighted average oil price realized for the year ended December 31, 2021 to $67.58 per Bbl, as compared to $37.38 per Bbl realized for the year ended December 31, 2020, and the 12% increase in our oil production to 17.8 million Bbl of oil for the year ended December 31, 2021, as compared to 15.9 million Bbl of oil for the year ended December 31, 2020. The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues increased by $346.0 million, or 232%, to $494.9 million for the year ended December 31, 2021, as compared to $149.0 million for the year ended December 31, 2020. The increase in natural gas revenues was primarily attributable to the almost three-fold increase in the weighted average natural gas price realized for the year ended December 31, 2021 to $6.06 per Mcf, as compared to $2.14 per Mcf realized for the year ended December 31, 2020, and the 18% increase in our natural gas production to 81.7 Bcf for the year ended December 31, 2021, as compared to 69.5 Bcf for the year ended December 31, 2020. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining natural gas production from our properties in the Haynesville shale.

Third-party midstream services revenues. Our third-party midstream services revenues increased $10.6 million, or 16%, to $75.5 million for the year ended December 31, 2021, as compared to $64.9 million for the year ended December 31, 2020. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to $37.6 million for the year ended December 31, 2021, as compared to $30.1 million for the year ended December 31, 2020, (ii) an increase in our third-party oil gathering and transportation revenues to $10.2 million for the year ended December 31, 2021, as compared to $9.4 million for the year ended December 31, 2020, and (iii) an increase in third-party produced water handling revenues to $27.6 million for the year ended December 31, 2021, as compared to $25.5 million for the year ended December 31, 2020.

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Sales of purchased natural gas. Our sales of purchased natural gas increased $44.3 million, or 106%, to $86.0 million for the year ended December 31, 2021, as compared to $41.7 million for the year ended December 31, 2020. This increase was primarily the result of the increase in realized natural gas prices and an increase in natural gas volumes sold during the year ended December 31, 2021. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at the Black River Processing Plant and subsequently sell the residue gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of operations.

Lease bonus - mineral acreage. We did not lease any of our mineral acreage to third parties during the year ended December 31, 2021. Our lease bonus - mineral acreage revenues were $4.1 million for the year ended December 31, 2020. Lease bonus - mineral acreage revenues reflect the payments we receive to enter into or extend leases to third-party lessees to develop the oil and natural gas attributable to certain of our mineral interests.

Realized (loss) gain on derivatives. Our realized net loss on derivatives was $220.1 million for the year ended December 31, 2021, as compared to a realized net gain of approximately $38.9 million for the year ended December 31, 2020. We realized a net loss of $197.5 million related to our oil costless collar and swap contracts for the year ended December 31, 2021, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts and above the strike price of certain of our oil swap contracts. We also realized a net loss of approximately $26.1 million related to our natural gas costless collar contracts for the year ended December 31, 2021, resulting primarily from natural gas prices that were above the ceiling prices of certain of our natural gas costless collar contracts. We realized a net gain of $3.5 million from our oil basis swap contracts for the year ended December 31, 2021, resulting from oil basis prices that were lower than the fixed prices of certain of our oil basis swap contracts. We realized a net gain of $35.1 million related to our oil costless collar, put and swap contracts for the year ended December 31, 2020, resulting primarily from oil prices that were below the floor prices of certain of our oil costless collar contracts and below the strike price of certain of our oil put and swap contracts. We realized a net gain of $3.8 million from our oil basis swap contracts for the year ended December 31, 2020, resulting from oil basis prices that were lower than the fixed prices of certain of our oil basis swap contracts. We realized an average loss on our oil derivatives of approximately $10.88 per Bbl of oil produced during the year ended December 31, 2021, as compared to an average gain of $2.45 per Bbl of oil produced during the year ended December 31, 2020. We realized an average loss on our natural gas derivatives of approximately $0.32 per Mcf of natural gas produced during the year ended December 31, 2021, as compared to no gain or loss on our natural gas derivatives during the year ended December 31, 2020. Our total oil volumes hedged for the year ended December 31, 2021 represented 61% of our total oil production, as compared to 77% of our total oil production for the year ended December 31, 2020. Our total natural gas volumes hedged for the year ended December 31, 2021 represented 62% of our total natural gas production, as compared to 10% of our total natural gas production for the year ended December 31, 2020.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $21.0 million for the year ended December 31, 2021, as compared to an unrealized loss of $32.0 million for the year ended December 31, 2020. During the year ended December 31, 2021, the aggregate net fair value of our open oil and natural gas derivatives and oil basis swap contracts increased from a net liability of approximately $35.9 million to a net liability of approximately $14.9 million, resulting in an unrealized gain on derivatives of approximately $21.0 million for the year ended December 31, 2021. During the year ended December 31, 2020, the aggregate net fair value of our open oil and natural gas derivative and oil basis swap contracts decreased from a net liability of approximately $3.9 million to a net liability of $35.9 million, resulting in an unrealized loss on derivatives of approximately $32.0 million for the year ended December 31, 2020.

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Expenses

    The following table summarizes our operating expenses and other income (expense) for the periods indicated.

						Year Ended December 31,
						2021						2020						2019
(In thousands, except expenses per BOE)
Expenses:
Production taxes, transportation and processing						$	178,987					$	93,338					$	92,273
Lease operating						108,964						104,953						117,305
Plant and other midstream services operating						61,459						41,500						36,798
Purchased natural gas						77,126						32,734						69,398
Depletion, depreciation and amortization						344,905						361,831						350,540
Accretion of asset retirement obligations						2,068						1,948						1,822
Full-cost ceiling impairment						—						684,743						—
General and administrative						96,396						62,578						80,054
Total expenses						869,905						1,383,625						748,190
Operating income						793,076						(521,499)						235,480
Other income (expense):
Net loss on asset sales and inventory impairment						(331)						(2,832)						(967)
Interest expense						(74,687)						(76,692)						(73,873)
Other (expense) income						(2,712)						1,864						(2,126)
Total other (expense) income						(77,730)						(77,660)						(76,966)
Income (loss) before income taxes						715,346						(599,159)						158,514
Total income tax provision (benefit)						74,710						(45,599)						35,532
Net income attributable to non-controlling interest in subsidiaries						(55,668)						(39,645)						(35,205)
Net income (loss) attributable to Matador Resources Company shareholders						$	584,968					$	(593,205)					$	87,777
Expenses per BOE:
Production taxes, transportation and processing						$	5.69					$	3.39					$	3.82
Lease operating						$	3.46					$	3.81					$	4.85
Plant and other midstream services operating						$	1.95					$	1.51					$	1.52
Depletion, depreciation and amortization						$	10.97					$	13.15					$	14.51
General and administrative						$	3.06					$	2.27					$	3.31

Year Ended December 31, 2021 as Compared to Year Ended December 31, 2020

Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $85.6 million, or 92%, to $179.0 million for the year ended December 31, 2021, as compared to $93.3 million for the year ended December 31, 2020. On a unit-of-production basis, our production taxes and transportation and processing expenses increased 68% to $5.69 per BOE for the year ended December 31, 2021, as compared to $3.39 per BOE for the year ended December 31, 2020. These increases were primarily attributable to the $76.5 million increase in our production taxes to $129.8 million for the year ended December 31, 2021, as compared to $53.4 million for the year ended December 31, 2020, resulting from the $956.1 million increase in oil and natural gas revenues for the year ended December 31, 2021, as compared to the year ended December 31, 2020 and the $9.2 million increase in transportation and processing expenses to $49.2 million for the year ended December 31, 2021, as compared to $40.0 million for the year ended December 31, 2020, primarily resulting from the 14% increase in total oil equivalent production between the respective periods.

Lease operating expenses. Our lease operating expenses increased $4.0 million, or 4%, to $109.0 million for the year ended December 31, 2021, as compared to $105.0 million for the year ended December 31, 2020. This increase in our lease operating expenses for the year ended December 31, 2021 was attributable to an increase in workover expenses of $4.0 million, which resulted from additional well maintenance operations conducted during the year-ended December 31, 2021, as compared to 2020. On a unit-of-production basis, our lease operating expenses decreased 9% to $3.46 per BOE for the year ended December 31, 2021, as compared to $3.81 per BOE for the year ended December 31, 2020, primarily resulting from the 14% increase in total oil equivalent production between the respective periods.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $20.0 million, or 48%, to $61.5 million for the year ended December 31, 2021, as compared to $41.5 million for the year ended December 31, 2020. This increase was primarily attributable to (i) increased expenses associated with our expanded commercial produced water disposal operations of $30.8 million for the year ended December 31, 2021, as compared to $21.8 million for the year ended December 31, 2020, (ii) increased expenses associated with our expanded pipeline operations of

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$17.5 million for the year ended December 31, 2021, as compared to $10.0 million for the year ended December 31, 2020, and (iii) increased expenses associated with operating the Black River Processing Plant of $13.1 million for the year ended December 31, 2021, as compared to $9.7 million for the year ended December 31, 2020.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased $16.9 million, or 5%, to $344.9 million for the year ended December 31, 2021, as compared to $361.8 million for the year ended December 31, 2020. On a unit-of-production basis, our depletion, depreciation and amortization expenses decreased 17% to $10.97 per BOE for the year ended December 31, 2021, as compared to $13.15 per BOE for the year ended December 31, 2020. These decreases were primarily attributable to the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded during the year ended December 31, 2020. These decreases were partially offset by (i) the 14% increase in total oil equivalent production to 31.5 million BOE for the year ended December 31, 2021, as compared to 27.5 million BOE for the year ended December 31, 2020, and (ii) increased depreciation expenses attributable to our midstream segment of approximately $31.5 million for the year ended December 31, 2021, as compared to $23.3 million for the year ended December 31, 2020.

Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment were recorded for the year ended December 31, 2021. Due to the sharp decline in oil and natural gas prices used to estimate proved oil and natural gas reserves in 2020, at June 30, 2020, September 30, 2020 and December 31, 2020, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling. As a result, we recorded an impairment charge of $684.7 million, exclusive of tax effect, to our net capitalized costs. This full-cost ceiling impairment is reflected in our consolidated statement of operations for the year ended December 31, 2020, with the related deferred income tax credit recorded net of a valuation allowance.

General and administrative. Our general and administrative expenses increased $33.8 million, or 54%, to $96.4 million for the year ended December 31, 2021, as compared to $62.6 million for the year ended December 31, 2020. Our general and administrative expenses on a unit-of-production basis increased 35% to $3.06 per BOE for the year ended December 31, 2021, as compared to $2.27 per BOE for the year ended December 31, 2020. These increases were largely attributable to employee compensation costs, including a $16.1 million increase in stock-based compensation expense primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period based upon our share price at the end of each reporting period. The share price of our common stock increased from $12.06 at December 31, 2020 to $36.92 at December 31, 2021. The remainder of the increase for the year ended December 31, 2021, as compared to December 31, 2020, resulted primarily from the reinstatement of employee compensation beginning in March 2021, which had been previously reduced beginning in March 2020 in response to the significantly lower oil and natural gas price environment at that time.

Interest expense. For the year ended December 31, 2021, we incurred total interest expense of approximately $79.5 million. We capitalized approximately $4.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2021 and expensed the remaining $74.7 million to operations. For the year ended December 31, 2020, we incurred total interest expense of approximately $82.2 million. We capitalized $5.5 million of our interest expense on certain qualifying projects for the year ended December 31, 2020 and expensed the remaining $76.7 million to operations.

Total income tax provision (benefit). At December 31, 2020, our deferred tax assets exceeded our deferred tax liabilities due to the deferred tax assets generated by impairment charges recorded in 2020. As a result, we established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2020. Due to a variety of factors, including our significant net income in 2021, our federal valuation allowance was reversed at September 30, 2021 as the deferred tax assets were determined to be more likely than not to be utilized. As a portion of our state net operating loss carryforwards are not expected to be utilized before expiration, a valuation allowance will continue to be recognized until the state deferred tax assets are more likely than not to be utilized. We recorded a total income tax provision of $74.7 million for the year ended December 31, 2021. Our effective tax rate was 11.3% for the year ended December 31, 2021, which differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of reversing the valuation allowance, but also due to permanent differences between book and taxable income and state taxes, primarily in New Mexico. We recorded a total income tax benefit of $45.6 million for the year ended December 31, 2020. Our effective tax rate was 7.6% for the year ended December 31, 2020, which differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the impact of the valuation allowance, but also due to permanent differences between book and taxable income and state taxes, primarily in New Mexico.

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Liquidity and Capital Resources

Our primary use of capital has been, and we expect will continue to be during 2022 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. Excluding any possible significant acquisitions, we expect to fund our capital expenditures for 2022 primarily through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2022, we expect to fund any such excess capital expenditures through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital.

At December 31, 2021, we had cash totaling $48.1 million and restricted cash totaling $38.8 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

At December 31, 2021, we had (i) $1.05 billion of outstanding 5.875% senior notes due September 2026 (the “Notes”), (ii) $100.0 million in borrowings outstanding under the Credit Agreement, (iii) approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and (iv) $7.5 million outstanding under an unsecured U.S. Small Business Administration (“SBA”) loan. In November 2021, the Company and lenders under our Credit Agreement entered into a Fourth Amended and Restated Credit Agreement, under which the borrowing base was increased to $1.35 billion. We elected to keep the borrowing commitment at $700.0 million, the maximum facility amount remained $1.5 billion and certain modifications were made to the terms of the Credit Agreement. These modifications include extending the maturity date to October 31, 2026, increasing the borrowing rate for a base rate loan or a Eurodollar loan under such facility by 0.50% and updating the key financial covenants under the Credit Agreement to require the Company to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter, and (ii) a debt to EBITDA ratio, which is defined as total debt outstanding (net of up to $75.0 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less. This November 2021 update to the Credit Agreement took the place of the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment (subject to compliance with the covenants noted above). We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2021. Between December 31, 2021 and February 28, 2022, we repaid an additional $25.0 million of borrowings outstanding under the Credit Agreement.

At December 31, 2021, San Mateo had $385.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures December 19, 2023 and was amended in June 2021 to increase the lender commitments under that facility from $375 million to $450 million (subject to San Mateo’s compliance with the covenants noted below) and to increase the borrowing rate for a base rate loan or a Eurodollar loan under such facility by 0.50%. The San Mateo Credit Facility contains an accordion feature, which, after the aforementioned amendment, provides for potential increases in lender commitments to up to $700.0 million. The San Mateo Credit Facility is guaranteed by San Mateo’s subsidiaries, secured by substantially all of San Mateo’s assets, including real property, and is non-recourse with respect to Matador and its wholly-owned subsidiaries. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2021. Between December 31, 2021 and February 22, 2022, we repaid an additional $30.0 million of borrowings outstanding under the San Mateo Credit Facility.

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On April 13, 2020, we executed a promissory note evidencing an unsecured loan in the amount of approximately $7.5 million as part of the Paycheck Protection Program. The Paycheck Protection Program was established under the Coronavirus Aid, Relief, and Economic Security Act and is administered by the SBA. The loan was issued through Iberiabank, which is a lender under the Credit Agreement, matures on the second anniversary of the funding date and bears interest at a fixed rate of 1.00% per annum. We used the proceeds of the loan for payroll, including salaries, payroll taxes and employee medical benefits, as permitted by the program. The receipt of the loan allowed us to avoid further reductions to employee headcount and salaries above those taken in March 2020. The loan is eligible for forgiveness for the portion of the loan proceeds used for payroll costs and other designated operating expenses, provided at least 60% of the loan’s proceeds are used for payroll costs. During 2021, we applied to the SBA for forgiveness of the Paycheck Protection Program loan, as all proceeds were used for payroll costs.

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2022. In the second half of 2021, we added a fifth contracted drilling rig in the Delaware Basin and plan to operate these five contracted drilling rigs in the Delaware Basin throughout 2022. In addition, at February 22, 2022, we had contracted a sixth operated drilling rig to begin drilling operations immediately on recently acquired acreage in western Lea County, New Mexico in our Ranger asset area. We expect to operate this sixth rig on the newly acquired acreage throughout the remainder of 2022. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2022 estimated capital expenditure budget consists of $640.0 to $710.0 million for D/C/E capital expenditures and $50.0 to $60.0 million for midstream capital expenditures, which primarily reflects our proportionate share of San Mateo’s estimated 2022 capital expenditures. Substantially all of these 2022 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, as well as amounts allocated to limited operations in our South Texas and Haynesville shale positions to maintain and extend leases and to participate in certain non-operated well opportunities. Our 2022 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells in 2022, including 90% with anticipated completed lateral lengths of two miles or greater.

We may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain mineral, royalty and midstream interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests, principally in the Delaware Basin, during 2022. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2022 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests for 2022.

Our 2022 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control.

Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2022 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2022 and the hedges we currently have in place. For a discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. We use commodity derivative financial instruments at times to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2021. See “Risk

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Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”

Our cash flows for the years ended December 31, 2021, 2020 and 2019 are presented below.

 

						Year Ended December 31,
						2021						2020						2019
(In thousands)
Net cash provided by operating activities						$	1,053,355					$	477,582					$	552,042
Net cash used in investing activities						(729,265)						(775,666)						(903,976)
Net cash (used in) provided by financing activities						(328,553)						324,339						333,078
Net change in cash						$	(4,463)					$	26,255					$	(18,856)
Adjusted EBITDA attributable to Matador Resources Company shareholders(1)						$	1,051,973					$	519,277					$	610,756

__________________

(1)Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below.

Cash Flows Provided by Operating Activities

Net cash provided by operating activities increased by $575.8 million to $1.05 billion for the year ended December 31, 2021, as compared to net cash provided by operating activities of $477.6 million for the year ended December 31, 2020. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $1.05 billion for the year ended December 31, 2021 from $500.7 million for the year ended December 31, 2020. This increase was primarily attributable to significantly higher realized oil and natural gas prices for the year ended December 31, 2021, as compared to the year ended December 31, 2020, as well as the 14% increase in total oil equivalent production during 2021, as compared to 2020. Changes in our operating assets and liabilities between December 31, 2020 and December 31, 2021 resulted in a net increase of approximately $22.1 million in net cash provided by operating activities for the year ended December 31, 2021, as compared to the year ended December 31, 2020.

Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-owned oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. For example, the effects of COVID-19 and the corresponding decline in oil demand significantly impacted the prices we received for our oil production in recent periods, particularly in 2020. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”

Cash Flows Used in Investing Activities

Net cash used in investing activities decreased by $46.4 million to $729.3 million for the year ended December 31, 2021 from $775.7 million for the year ended December 31, 2020. This decrease in net cash used in investing activities was primarily attributable to a decrease of $40.0 million in D/C/E capital expenditures as compared to the year ended December 31, 2020, and a decrease of approximately $171.0 million in expenditures for midstream support equipment and facilities, resulting from completing the construction of the further expansion of the Black River Processing Plant and associated infrastructure, additional salt water disposal wells and additional pipeline infrastructure during 2020. These decreases were partially offset by an increase of $165.8 million in expenditures primarily related to our acquisition of oil and natural gas properties in the

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Delaware Basin during 2021. Cash used for D/C/E capital expenditures for the year ended December 31, 2021 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin.

Cash Flows (Used in) Provided by Financing Activities

Net cash used in financing activities was $328.6 million for the year ended December 31, 2021, as compared to net cash provided by financing activities of $324.3 million for the year ended December 31, 2020. The net cash used in financing activities for the year ended December 31, 2021 was primarily attributable to (i) net repayments under our Credit Agreement of $340.0 million, (ii) net borrowings under the San Mateo Credit Facility of $51.0 million, (iii) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $13.4 million and (iv) dividends paid of $14.6 million.

See Note 7 to the consolidated financial statements in this Annual Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility and the Notes.

Guarantor Financial Information

The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2021, the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries are not guarantors of the Notes.

The following tables present summarized financial information of Matador (as issuer of the Notes) and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. This financial information is presented in accordance with the amended requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations or financial position had the Guarantor Subsidiaries operated as independent entities.

(in thousands)
Summarized Balance Sheet						December 31, 2021
Assets
Current assets						$	305,712
Net property and equipment						$	3,060,233
Other long-term assets						$	48,890
Liabilities
Current liabilities						$	461,013
Long-term debt						$	1,142,580
Other long-term liabilities						$	138,010

(in thousands)						Year Ended
Summarized Statement of Operations						December 31, 2021
Revenues						$	1,543,420
Expenses						873,037
Operating income						$	670,383
Other expense						(67,823)
Tax provision						(74,710)
Net income						$	527,850

Non-GAAP Financial Measures

We define Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

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Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively.

						Year Ended December 31,
						2021						2020						2019
(In thousands)
Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss):
Net income (loss) attributable to Matador Resources Company shareholders						$	584,968					$	(593,205)					$	87,777
Net income attributable to non-controlling interest in subsidiaries						55,668						39,645						35,205
Net income (loss)						640,636						(553,560)						122,982
Interest expense						74,687						76,692						73,873
Total income tax provision (benefit)						74,710						(45,599)						35,532
Depletion, depreciation and amortization						344,905						361,831						350,540
Accretion of asset retirement obligations						2,068						1,948						1,822
Full-cost ceiling impairment						—						684,743						—
Unrealized (gain) loss on derivatives						(21,011)						32,008						53,727
Non-cash stock-based compensation expense						9,039						13,625						18,505
Net loss on asset sales and impairment						331						2,832						967
Expense related to contingent consideration						1,485						—						—
Consolidated Adjusted EBITDA						1,126,850						574,520						657,948
Adjusted EBITDA attributable to non-controlling interest in subsidiaries						(74,877)						(55,243)						(47,192)
Adjusted EBITDA attributable to Matador Resources Company shareholders						$	1,051,973					$	519,277					$	610,756

						Year Ended December 31,
						2021						2020						2019
(In thousands)
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by    Operating Activities:
Net cash provided by operating activities						$	1,053,355					$	477,582					$	552,042
Net change in operating assets and liabilities						982						23,078						34,517
Interest expense, net of non-cash portion						71,028						73,860						71,389
Expense related to contingent consideration						1,485						—						—
Adjusted EBITDA attributable to non-controlling interest in subsidiaries						(74,877)						(55,243)						(47,192)
Adjusted EBITDA attributable to Matador Resources Company shareholders						$	1,051,973					$	519,277					$	610,756

For the year ended December 31, 2021, we reported net income attributable to Matador shareholders of $585.0 million, as compared to a net loss attributable to Matador shareholders of $593.2 million for the year ended December 31, 2020. This increase primarily resulted from (i) significantly higher realized oil and natural gas prices and higher oil and natural gas production, for the year ended December 31, 2021, as compared to the year ended December 31, 2020, and (ii) no full-cost ceiling impairment recorded for the year ended December 31, 2021, as compared to $684.7 million recorded for the year ended December 31, 2020. These increases were partially offset by a realized loss on derivatives of $220.1 million for the year ended December 31, 2021, as compared to a realized gain on derivatives of $38.9 million for the year ended December 31, 2020, and an income tax provision of $74.7 million for the year ended December 31, 2021, as compared to an income tax benefit of $45.6 million for the year ended December 31, 2020.

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Adjusted EBITDA, a non-GAAP financial measure, increased $532.7 million to $1.05 billion for the year ended December 31, 2021, as compared to $519.3 million for the year ended December 31, 2020. This increase was primarily attributable to the significantly higher realized oil and natural gas prices and higher oil and natural gas production noted above for the year ended December 31, 2021, as compared to the year ended December 31, 2020.

Off-Balance Sheet Arrangements

 From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2021, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.

Obligations and Commitments

We had the following material contractual obligations and commitments at December 31, 2021.

						Payments Due by Period
						Total						Less Than 1 Year						1-3 Years						3-5 Years						More Than 5 Years
(In thousands)
Contractual Obligations:
Borrowings, including letters of credit(1)						$	547,273					$	—					$	401,470					$	145,803					$	—
Senior unsecured notes(2)						1,050,000						—						—						1,050,000						—
Office leases						18,483						4,123						8,529						5,831						—
Non-operated drilling and other capital commitments(3)						65,414						45,614						19,800						—						—
Drilling rig contracts(4)						10,835						10,835						—						—						—
Asset retirement obligations(5)						41,959						270						5,074						1,518						35,097
Transportation, gathering, processing and disposal agreements with non-affiliates(6)						597,334						70,014						143,424						142,185						241,711
Transportation, gathering, processing and disposal agreements with San Mateo(7)						390,307						—						100,101						182,740						107,466
Total contractual cash obligations						$	2,721,605					$	130,856					$	678,398					$	1,528,077					$	384,274

__________________

(1)The amounts included in the table above represent principal maturities only. At December 31, 2021, we had $100.0 million of borrowings outstanding under the Credit Agreement, approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement and $7.5 million in borrowings under the SBA loan. The Credit Agreement matures in October 2026. At December 31, 2021 San Mateo had $385.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures in December 2023. Assuming the amounts outstanding and interest rates of 1.85% and 2.11%, for the Credit Agreement and the San Mateo Credit Facility, respectively, at December 31, 2021, the interest expense for such facilities is expected to be approximately $1.9 million and $8.2 million each year until maturity.

(2)The amounts included in the table above represent principal maturities only. Interest expense on the $1.05 billion of Notes that were outstanding as of December 31, 2021 is expected to be approximately $61.7 million each year until maturity.

(3)At December 31, 2021, we had outstanding commitments to drill and complete and to participate in the drilling and completion of various operated and non-operated wells.

(4)We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.

(5)The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at December 31, 2021.

(6)From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal. Certain of these agreements contain minimum volume commitments. If we do not meet the minimum volume commitments under these agreements, we would be required to pay certain deficiency fees. See Note 14 to the consolidated financial statements in this Annual Report for more information about these contractual commitments.

(7)We dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced

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water disposal agreements. In addition, we dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.

General Outlook and Trends

Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, political instability in Russia, Ukraine, China and the Middle East, the actions of OPEC+, the worldwide spread of COVID-19, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors.

The prices we receive for oil, natural gas and NGLs heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs we can produce economically, and, as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the leverage ratio covenant under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”

During the first quarter and through April 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63 per Bbl in early January to as low as ($38) per Bbl in late April. This sudden decline in oil prices was attributable to two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (ii) the increase in global oil supply resulting from the actions of OPEC+. The sudden decline in oil prices began to improve later in the second quarter of 2020 and generally continued throughout the remainder of 2020.

During the year ended December 31, 2021 and through February 22, 2022, the oil and natural gas industry experienced continued improvement in commodity prices, as compared to 2020, primarily resulting from (x) improvements in oil demand as the impact from COVID-19 has begun to abate, (y) actions taken by OPEC+ to reduce the worldwide supply of oil through coordinated production cuts and (z) changes in supply and demand dynamics, particularly with respect to natural gas markets generally and, more recently, instability in Russia and Ukraine. While oil and natural gas prices improved significantly in 2021 and early 2022, the general outlook for the oil and natural gas industry for the remainder of 2022 remains unclear, and we can provide no assurances that commodity prices will remain at current levels or increase further. In fact, commodity prices may decline from their current levels, particularly in response to the spread of new variants, if any, of COVID-19, the actions of OPEC+ and other governmental authorities to increase the global oil supply and milder weather conditions, among other factors. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil and natural gas. Low oil and natural gas prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations” in this Annual Report. The economic disruptions associated with COVID-19 and the volatility in oil and natural gas prices have also impacted our ability to access the capital markets on reasonably similar terms as were available prior to 2020.

For the year ended December 31, 2021, oil prices averaged $68.11 per Bbl, as compared to $39.34 per Bbl in 2020, ranging from a low of $47.62 per Bbl in early January to a high of $84.65 per Bbl in late October, based upon the WTI oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $67.58 per Bbl ($56.70 per Bbl including realized losses from oil derivatives) for our oil production for the year ended December 31, 2021, as compared to $37.38 per Bbl ($39.83 per Bbl including realized gains from oil derivatives) for the year ended December 31, 2020. At February 22, 2022, the WTI oil futures contract price for the earliest delivery date had increased from year-end 2021, closing at $92.35 per Bbl, and was higher compared to $61.49 per Bbl on February 22, 2021. We are uncertain that oil prices will remain at these levels as noted above.

Natural gas prices also improved significantly during 2021. For the year ended December 31, 2021, natural gas prices averaged $3.71 per MMBtu, as compared to $2.13 per MMBtu in 2020, ranging from a low of $2.45 per MMBtu in late January to a high of $6.31 per MMBtu in early October. As a result of milder-than-expected winter weather, natural gas prices declined over the course of the fourth quarter of 2021, finishing the year at $3.73 per MMBtu. We realized a weighted average natural gas price of $6.06 per Mcf ($5.74 per Mcf including realized losses from natural gas derivatives) for our natural gas production for the year ended December 31, 2021, as compared to $2.14 per Mcf (with no realized gains or losses from natural gas derivatives) for the year ended December 31, 2020. As a two-stream reporter, the revenues associated with our NGL production are included in the weighted average natural gas price. At February 22, 2022, the NYMEX Henry Hub natural gas futures

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contract price for the earliest delivery date had increased from year-end 2021, closing at $4.50 per MMBtu, and was higher as compared to $2.95 per MMBtu at February 22, 2021. We are uncertain that natural gas prices will remain at these levels, particularly as we exit the winter heating season.

From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under the Credit Agreement and through the capital markets. During year ended December 31, 2021, we incurred realized losses on our oil and natural derivative contracts of approximately $220.1 million, primarily as a result of oil and natural prices that were above the ceiling prices of certain of our oil and natural gas costless collar contracts and above the strike price of certain of our oil swap and oil basis swap contracts. At February 22, 2022, almost all of the derivative contracts we had in place that contributed to these realized losses on derivatives in 2021 had expired. At February 22, 2022, given current oil and natural gas prices and the oil and natural gas derivative contracts we have in place, we do not anticipate losses of such magnitude from our derivative contracts in 2022, although there may be periods where we realize losses from derivatives. At December 31, 2021, adjusted for derivative contracts entered into between January 1, 2022 and February 22, 2022, we had derivative contracts in place for approximately 5.1 million Bbl of our anticipated full year 2022 oil production and approximately 54.7 Bcf of our anticipated full year 2022 natural gas production.

The prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At December 31, 2021, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas.

The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years but began 2020 slightly positive to the WTI oil price and remained positive through much of the first quarter. With the abrupt decline in oil prices during the first quarter of 2020, however, the Midland-Cushing (Oklahoma) oil price differential experienced significant volatility in April 2020, reaching ($6.00) per Bbl before becoming positive later in the second quarter and improving throughout the rest of 2020 and 2021 and into early 2022. At February 22, 2022, this oil price differential was approximately +$1.00 per Bbl. At February 22, 2022, we had derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential on a portion of our anticipated full year 2022 oil production.

Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years, including times in April 2019 when natural gas was being sold at the Waha hub for negative prices as high as ($7.00) to ($9.00) per MMBtu. In early 2020, the Waha basis differential remained significant at about ($1.20) per MMBtu and continued to deteriorate. Natural gas prices at the Waha hub were negative again on certain days in April 2020. The Waha basis differential narrowed during the remainder of the second quarter of 2020. During the third quarter of 2020 and, in particular, at the beginning of October 2020, the Waha basis differential widened significantly again, including several days when natural gas was being sold at the Waha hub for negative prices, due to seasonal pipeline maintenance and other factors that reduced capacity out of the Waha hub. These capacity issues have been largely resolved and the Waha basis differential improved during the remainder of 2020 and 2021. In early 2022, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin, particularly beginning in the latter half of 2022, began to increase. As a result, the Waha basis differential began to widen, and, at February 22, 2022, this natural gas price differential was approximately ($0.60) per MMBtu.

A significant portion of our Delaware Basin natural gas production is sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2021, we typically realized a premium to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing. Further, approximately 11% of our reported natural gas production for the year ended December 31, 2021 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing.

Although the natural gas price differentials have recently at times been positive or close to zero, these price differentials could deteriorate in future periods. Should we experience future periods of negative pricing for natural gas as we have in previous periods, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. In addition, we have no derivative contracts in place to mitigate our exposure to these natural gas price differentials in 2022.

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At February 22, 2022, we had not experienced material pipeline-related interruptions to our oil, natural gas or NGL production. In certain periods over the last few years, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can provide no assurances that such problems will not arise. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected.

As a result of the recent increases in oil and natural gas prices, we have begun to experience inflation in the costs of certain oilfield services, including diesel, steel, labor, trucking, personnel and completion costs, among others. Should oil and natural gas prices remain at their current levels or increase further, we expect to be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. We budgeted a 10 to 15% increase in oilfield service costs, as compared to the fourth quarter of 2021, in preparing our full-year D/C/E and midstream capital expenditures for 2022. Should we experience service cost inflation above 10 to 15% during 2022, we may be required to increase our 2022 estimated capital expenditure budget. Further, in early 2022, supply chain disruptions being experienced throughout the United States and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely fashion, which could result in delays to our operations and could, in turn, adversely affect our business, financial condition, results of operations and cash flows.

In addition, should oil and natural gas prices remain at their current levels throughout 2022, we may exhaust our federal or state net operating loss carryforwards and become subject to federal and state income taxes in future periods. At February 22, 2022, given our current projections, we do not expect to pay significant federal income taxes, if any, in 2022, but may pay federal income taxes in 2023. We may pay state income taxes in 2022 and 2023, however, in New Mexico and Texas.

Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For example, although such bills have not passed, in recent years, various bills have been introduced in the New Mexico legislature proposing to add a surtax on natural gas processors and proposing to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The NMED has proposed similar rules and regulations. These and other laws, rules and regulations, including any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have an adverse impact on our business, financial condition, results of operations and cash flows. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders. In addition, the BLM has indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation may delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed at December 31, 2021, the impact of federal actions related to the oil and natural gas industry remains unclear, and should other limitations or prohibitions be imposed or continue to be applied, our operations on federal lands could be adversely impacted. Such limitations or prohibitions would almost certainly impact our 2022 and future drilling and completion plans and could materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”

We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity, also known as “induced seismicity.” This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regarding waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to

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impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, and could result in increased costs and additional operating restrictions or delays, that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. The adoption of such legislation and regulations could also decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions for San Mateo as well. See “Risk Factors—Risks Related to Laws and Regulations—The potential adoption of federal, state and local legislation and regulations intended to address potential induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays.”

Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Equity returns in the sector prior to 2021 versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices and some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations.

Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A significant reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and the availability under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth.”

We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2021.

Oil and Natural Gas Properties

We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the

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amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of:

(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less

(d) any income tax effects related to the properties involved.

Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. Our derivative instruments are not considered in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes.

Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue

Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time.

Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors—Risks Related to our Financial Condition—Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” and “Risk Factors—Risks Related to our Financial Condition—We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.”

Estimates of proved oil and natural gas reserves are key inputs used for the calculations of depletion, the ceiling test and the fair value assigned to proved oil and gas reserves acquired in a business combination. The estimated present value of future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The associated commodity prices and the applicable discount rate used to determine the fair value assigned to proved oil and gas reserves acquired in a business combination are based upon a variety of factors on the date of acquisition. The associated commodity prices and the applicable discount rate used in estimates for depletion and the ceiling test are in accordance with

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guidelines established by the SEC. Under these guidelines, future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues.

Derivative Financial Instruments

From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Prior to settlement, our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently as an unrealized gain or loss on derivatives in our consolidated statements of operations. Changes in the fair value of these open derivative financial instruments can have a significant impact on our reported results from period to period but do not impact our cash flows from operations, liquidity or capital resources. The fair value of our open derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Stock-Based Compensation

We may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan then in effect to members of our Board of Directors and certain employees, contractors and advisors. We use the fair value method to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest over three or four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. We use our own historical volatility to estimate the future volatility of our stock.

We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method to determine the fair value of awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards is recognized based on the closing price of our common stock on the date of the grant for awards issued under the 2012 Incentive Plan and on the trading day prior to the date of grant for awards issued under the 2019 Incentive Plan. See Note 9 to the consolidated financial statements in this Annual Report for further details on our stock-based compensation at December 31, 2021.

Income Taxes

We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition.

We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes.

Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production.

We typically use costless (or zero-cost) collars, three-way collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. Costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a

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call option. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option or options and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection.

We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2021, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), PNC Bank and Royal Bank of Canada (or affiliates thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments.

At December 31, 2021, we had entered into various costless collar contracts to mitigate our exposure to fluctuations in oil and natural gas prices, each with an established price floor and ceiling. When the settlement price is below the price floor established by one or more of these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil or natural gas volume. When the settlement price is above the price ceiling established by one or more of the costless collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume.

At December 31, 2021, we had entered into various swap contracts to mitigate our exposure to oil price differences between NYMEX WTI Cushing and Argus WTI Midland crude oil. When the settlement price is below the fixed price established by one or more of these basis swaps, we receive from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. When the settlement price is above the fixed price established by one or more of these basis swaps, we pay to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume.

See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2021. Such information is incorporated herein by reference.

Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors—Risks Related to Laws and Regulations—The derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business.”

Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt. At December 31, 2021, we had outstanding borrowings of $100.0 million at an interest rate of 1.85% per annum under our Credit Agreement, $1.05 billion in Notes outstanding at a coupon rate of 5.875% per annum and $385.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 2.11% per annum. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers and San Mateo is subject to the credit risk of its customers. The inability or failure of our or San Mateo’s significant customers to meet their obligations or their insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties.

While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the

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customer cannot and (ii) undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative financial instruments in place at February 22, 2022 were The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), PNC Bank, Royal Bank of Canada and Truist Bank (or affiliates thereof), and all but BMO Harris Financing were lenders (or affiliates thereof) under our Credit Agreement, and we are likely to enter into any future derivative instruments with such banks or other lenders (or affiliates thereof) party to the Credit Agreement.

Impact of Inflation. Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2021, 2020 and 2019. Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the U.S. economy and has become much more significant in recent months, reaching its highest levels in approximately 40 years. At February 22, 2022, we do not know how long these inflationary pressures may persist or the impact they may have on our business moving forward. We tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. We have begun to experience such inflationary pressure in our drilling and completion and midstream operations, and we budgeted a 10 to 15% increase in oil field service costs, as compared to the fourth quarter of 2021, in preparing our full year 2022 D/C/E and midstream capital expenditures estimates. See “Risk Factors—Risks Related to our Operations—The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows.”

Item 8. Financial Statements and Supplementary Data.

Our financial statements appear at the end of this Annual Report beginning on page F-1.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

Not applicable.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2021 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2021, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2021 as included herein.

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Important Considerations

The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management.

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Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors

Matador Resources Company:

Opinion on Internal Control Over Financial Reporting

We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements), and our report dated February 28, 2022 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/    KPMG LLP

Dallas, Texas

February 28, 2022

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Item 9B. Other Information.

Not applicable.

PART III

 

Item 10. Directors, Executive Officers and Corporate Governance.

The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement for our 2022 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report (our “Definitive Proxy Statement”). Such responsive information is expected to be included under the captions “Proposal 1—Election of Directors,” “Corporate Governance,” “Executive Compensation” and “Director Compensation.”

Item 11. Executive Compensation.

The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Executive Compensation.”

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5 of this Annual Report and is incorporated herein by reference. Other information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management.”

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance—Independence of Directors.”

Item 14. Principal Accounting Fees and Services.

The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Proposal 3—Ratification of Appointment of KPMG LLP.”

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PART IV

Item 15. Exhibits and Financial Statement Schedules.

The following documents are filed as part of this Annual Report:

1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2021 and 2020, Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019, Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2021, 2020 and 2019 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019.

2. Financial Statement Schedules: All other schedules for which provision is made in the applicable accounting regulations of the SEC are omitted because the required information is either not applicable, not required or is shown in the respective financial statements or in the notes thereto.

3. Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index included below.

Item 16. Form 10-K Summary.

None.

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EXHIBIT INDEX

Exhibit Number						Description
2.1						Subscription and Contribution Agreement, dated as of February 17, 2017, by and among Longwood Midstream Holdings, LLC, FP MMP Holdings LLC and San Mateo Midstream, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 24, 2017).*
3.1						Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).
3.2						Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).
3.3						Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).
3.4						Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 22, 2018).
4.1						Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1 filed on January 19, 2012).
4.2						Indenture, dated as of August 21, 2018, by and among Matador Resources Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on August 21, 2018).
4.3						First Supplemental Indenture, dated as of February 27, 2019, by and among Matador Resources Company, WR Permian, LLC, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Annual Report on Form 10-K for the year ended December 31, 2018).
4.4						Second Supplemental Indenture, dated as of December 14, 2021, by and among Matador Resources Company, the subsidiary guarantors party thereto and Computershare Trust Company, N. A., as agent for Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on December 14, 2021).
4.5						Description of Capital Stock (incorporated by reference to Exhibit 4.4 to the Annual Report on Form 10-K for the year ended December 31, 2019).
10.1†						Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011).
10.2†						Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011).
10.3†						Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011).
10.4†						First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011).
10.5†						First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011).
10.6†						First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011).
10.7†						Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011).
10.8†						Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011).

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10.9†						Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to the Registration Statement on Form S-1 filed on December 30, 2011).
10.10†						Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013).
10.11†						Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective February 5, 2015 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended December 31, 2014).
10.12†						Form of Employment Agreement between Matador Resources Company and each of Billy E. Goodwin and G. Gregg Krug, effective February 19, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
10.13†						First Amendment to the Employment Agreement between Matador Resources Company and Billy E. Goodwin (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018).
10.14†						First Amendment to the Employment Agreement between Matador Resources Company and G. Gregg Krug (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
10.15†						Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2018).
10.16†						First Amendment to the Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
10.17†						Second Amendment to the Amended and Restated Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the year ended December 31, 2020).
10.18†						Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1 filed on November 14, 2011).
10.19						Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2012).
10.20						Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012).
10.21						Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012).
10.22						First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012).
10.23						Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 6, 2013).
10.24						Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013).

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10.25						Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013).
10.26						Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 8, 2014).
10.27						Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of April 14, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 14, 2015).
10.28						Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 21, 2015).
10.29						Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 2, 2016).
10.30						Limited Consent and Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of December 9, 2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 9, 2016).
10.31						Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 28, 2017, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 4, 2017).
10.32						Eleventh Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 9, 2018).
10.33						Limited Consent and Twelfth Amendment to Third Amended and Restated Credit Agreement, dated as of October 1, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on October 4, 2018).
10.34						Thirteenth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2018, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 1, 2018).
10.35						Fourteenth Amendment to Third Amended and Restated Credit Agreement, dated as of February 27, 2020, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the year ended December 31, 2019).
10.36						Fifteenth Amendment to Third Amended and Restated Credit Agreement, dated as of April 23, 2021, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 29, 2021).
10.37						Fourth Amended and Restated Credit Agreement, dated as of November 18, 2021, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 18, 2021).
10.38†						Matador Resources Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.59 to the Annual Report on Form 10-K for the year ended December 31, 2015).
10.39†						Matador Resources Company Annual Cash Incentive Plan, effective as of January 1, 2019 (incorporated by reference to Exhibit 10.66 to the Annual Report on Form 10-K for the year ended December 31, 2018).
10.40†						Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 11, 2015).

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10.41†						Amendment Number One to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).
10.42†						Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the year ended December 31, 2015).
10.43†						Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2015).
10.44†						Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K for the year ended December 31, 2016).
10.45†						Form of Restricted Stock Unit Award Agreement for Annual Grants with delayed delivery relating to the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).
10.46†						Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).
10.47†						Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).
10.48†						Form of Nonqualified Stock Option Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).
10.49†						Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).
10.50†						Form of Restricted Stock Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).
10.51†						Form of Phantom Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.67 to the Annual Report on Form 10-K for the year ended December 31, 2018).
10.52†						Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.68 to the Annual Report on Form 10-K for the year ended December 31, 2018).
10.53†						Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to the Registration Statement on Form S-8 filed on June 6, 2019).
10.54†						Form of Restricted Stock Unit Award Agreement for director awards under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
10.55†						Form of Restricted Stock Unit Award Agreement for director awards with deferred delivery under the Matador Resources Company 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
10.56†						Form of Phantom Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020).
10.57†						Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020).
10.58†						Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees with employment agreements (filed herewith).
10.59†						Form of Performance Stock Unit Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan for employees without employment agreements (filed herewith).

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10.60†						Form of Restricted Stock Award Agreement for awards under the Matador Resources Company 2019 Long-Term Incentive Plan with ratable vesting for employees without employment agreements (filed herewith).
10.61†						Form of Stock Option Cancellation Agreement for certain stock options under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.56 to the Annual Report on Form 10-K for the year ended December 31, 2020).
21.1						List of Subsidiaries of Matador Resources Company (filed herewith).
23.1						Consent of KPMG LLP (filed herewith).
23.2						Consent of Netherland, Sewell & Associates, Inc. (filed herewith).
31.1						Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.2						Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32.1						Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
32.2						Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
99.1						Audit report of Netherland, Sewell & Associates, Inc. (filed herewith).
101						The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2021, formatted in Inline XBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith).
104						Cover Page Interactive Data File, formatted in Inline XBRL (included as Exhibit 101).
†						Indicates a management contract or compensatory plan or arrangement.
*						Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

MATADOR RESOURCES COMPANY

February 28, 2022

By:

/s/ Joseph Wm. Foran

Joseph Wm. Foran

Chairman and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

Title

Date

/s/ Joseph Wm. Foran

Chairman and Chief Executive Officer

February 28, 2022

Joseph Wm. Foran

(Principal Executive Officer)

/s/ David E. Lancaster

Executive Vice President and Chief Financial Officer

February 28, 2022

David E. Lancaster

(Principal Financial Officer)

/s/ Robert T. Macalik

Senior Vice President and Chief Accounting Officer

February 28, 2022

Robert T. Macalik

(Principal Accounting Officer)

/s/ Reynald A. Baribault

Director

February 28, 2022

Reynald A. Baribault

/s/ R. Gaines Baty

Director

February 28, 2022

R. Gaines Baty

/s/ William M. Byerley

Director

February 28, 2022

William M. Byerley

/s/ Monika U. Ehrman

Director

February 28, 2022

Monika U. Ehrman

/s/ Julia P. Forrester Rogers

Director

February 28, 2022

Julia P. Forrester Rogers

/s/ James M. Howard

Director

February 28, 2022

James M. Howard

/s/ Timothy E. Parker

Director

February 28, 2022

Timothy E. Parker

/s/ Kenneth L. Stewart

Director

February 28, 2022

Kenneth L. Stewart

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report.

Batch drilling. The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil, other liquid hydrocarbons or produced water.

Bcf. One billion cubic feet of natural gas.

Bench. A geologic zone or formation or a subdivision of a geologic formation.

BOE. Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or NGLs to six Mcf of natural gas.

BOE/d. BOE per day.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Central delivery point or CDP. The point on an oil, natural gas or produced water system where such product is aggregated from one or more gathering or transportation pipelines, wells, tank batteries or leases. Custody is often transferred to a third party at a central delivery point.

Completion. The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reservoir.

Conventional reservoirs or resources. Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore.

Coring. The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined.

Developed acreage. The number of acres that are allocated or assignable to productive wells.

Development well. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. The difference between a particular oil or natural gas price and the applicable benchmark price, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price.

Dry hole. A well found to be incapable of producing hydrocarbons.

ESP. Electric submersible pump.

Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Farmin or farmout. An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.”

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells in which a working interest is owned.

Held by production. An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property.

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Horizontal drilling or well. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption.

Hydraulic fracturing. The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation.

Lateral length. Length of the drilled or completed portion of a horizontal well.

Liquids. Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility.

MBbl. One thousand barrels of crude oil, other liquid hydrocarbons or produced water.

MBOE. One thousand BOE.

Mcf. One thousand cubic feet of natural gas.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

NGL. Natural gas liquids.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells.

Net revenue interest. The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well.

NYMEX. New York Mercantile Exchange.

Organization of Petroleum Exporting Countries or OPEC. An intergovernmental group of 13 of the world’s major oil-exporting countries, which was founded in 1960 to coordinate the petroleum policies of its members and to provide member countries with technical and economic aid.

OPEC+. A loose affiliation of the member countries of OPEC and 10 of the world’s other major oil-exporting countries, including Russia.

Overriding royalty interest. A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest.

Pad. The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well.

Pad drilling. The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated.

Permeability. A reference to the ability of oil and/or natural gas to flow through a reservoir.

Petrophysical analysis. The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties.

Play. A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type.

Possible reserves. Additional reserves that are less certain to be recognized than probable reserves.

Probable reserves. Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered.

Producing well, or productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes.

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Properties. Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other mineral fee, leasehold and related interests.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons.

Prospectivity. Having the potential for the discovery and/or future development of commercial hydrocarbons in a specific geographic area or formation.

Proved developed non-producing. Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves.

Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.

Proved reserves. Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned.

Repeatability. The potential ability to drill multiple wells within a prospect or trend.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

2-D seismic. The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflection seismic data collected along a single source profile.

3-D seismic. The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production.

Spud. The act of beginning to drill an oil or natural gas well.

Throughput. The volume of product transported or passing through a pipeline, plant or other facility.

Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.

Unconventional resource play. A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells.

Unproved and unevaluated properties. Properties where no drilling or other actions have been undertaken that permit such properties to be classified as proved and to which no proved reserves have been assigned.

Vertical well. A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped.

Visualization. An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information.

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Volumetric reserves analysis. A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor.

Wellbore. The hole made by a well.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

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Matador Resources Company and Subsidiaries

CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2021, 2020 and 2019

Index

 

Report of Independent Registered Public Accounting Firm			F-2
Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2021 and 2020			F-4
Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019			F-5
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2021, 2020 and 2019			F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019			F-7
Notes to Consolidated Financial Statements			F-8
Unaudited Supplementary Information			F-37

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Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors

Matador Resources Company:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries (the Company) as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2022 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on depletion expense and the ceiling test calculation

As discussed in Note 2 to the consolidated financial statements, the Company uses the full-cost method of accounting for its investments in oil and natural gas properties and amortizes capitalized costs of oil and natural gas properties using the unit-of-production method based on production and estimates of proved reserves quantities. The Company is required to perform a ceiling test calculation on a quarterly basis and the applicable ceiling is equal to the sum of (1) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (2) unproved and unevaluated property costs not being amortized, plus (3) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (4) any income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling is charged to operations as a full-cost ceiling impairment. Estimates of economically recoverable oil and natural gas reserves depend upon a number of factors and assumptions, including quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the operating costs incurred, the amount of future development expenditures, and the price received for the production. For the year ended December 31, 2021, the Company recorded depletion expense of evaluated oil and natural gas

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properties of $310.1 million. Additionally, as discussed in Note 3 to the consolidated financial statements, the Company recorded $6.0 billion of gross evaluated oil and natural gas properties as of December 31, 2021. The Company’s internal reserves engineers prepare an estimate of the proved oil and natural gas reserves, and the Company engages external reserves engineers to independently evaluate the proved oil and natural gas reserves estimated by the Company.

We identified the assessment of the impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on both depletion expense and the ceiling test calculation as a critical audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and natural gas reserves as auditor judgment was required to evaluate the assumptions used by the Company related to forecasted production, development costs, operating costs, and forecasted oil and natural gas prices inclusive of price differentials.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depletion and ceiling test processes. This included controls related to the development of the assumptions listed above used to estimate proved reserves used in the respective calculations. We evaluated (1) the professional qualifications of the Company’s internal reserves engineers as well as the external reserves engineers and external engineering firm, (2) the knowledge, skill, and ability of the Company’s internal and external reserves engineers, and (3) the relationship of the external reserves engineers and external engineering firm to the Company. We assessed the methodology used by the Company to estimate the reserves for consistency with industry and regulatory standards. We also compared the pricing assumptions, including price differentials, used in the reserves engineers’ estimate of the proved reserves to publicly available oil and natural gas pricing data. We evaluated assumptions used in the reserves engineers’ estimate regarding future operating and development costs based on historical actual results. In addition, we compared the Company’s historical production forecasts to actual production volumes to assess the Company’s ability to accurately forecast and compared the forecasted production assumption used by the Company in the current period to historical production. We read the findings of the Company’s external reserves engineers in connection with our evaluation of the Company’s reserves estimates. We analyzed the depletion expense calculation for compliance with industry and regulatory standards, and recalculated it. We also analyzed the ceiling test impairment calculation for compliance with industry and regulatory standards. In addition, we performed an independent calculation of the ceiling test impairment calculation and compared our results with the Company’s results.

/s/ KPMG LLP

We have served as the Company’s auditor since 2014.

Dallas, Texas

February 28, 2022

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Matador Resources Company and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(In thousands, except par value and share data)

						December 31,
						2021						2020
ASSETS
Current assets
Cash						$	48,135					$	57,916
Restricted cash						38,785						33,467
Accounts receivable
Oil and natural gas revenues						164,242						85,098
Joint interest billings						48,366						34,823
Other						28,808						17,212
Derivative instruments						1,971						6,727
Lease and well equipment inventory						12,188						10,584
Prepaid expenses and other current assets						28,810						15,802
Total current assets						371,305						261,629
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated						6,007,325						5,295,931
Unproved and unevaluated						964,714						902,133
Midstream properties						900,979						841,695
Other property and equipment						30,123						29,561
Less accumulated depletion, depreciation and amortization						(4,046,456)						(3,701,551)
Net property and equipment						3,856,685						3,367,769
Other assets
Derivative instruments						—						2,570
Other long-term assets						34,163						55,312
Total assets						$	4,262,153					$	3,687,280
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable						$	26,256					$	13,982
Accrued liabilities						253,283						119,158
Royalties payable						94,359						66,049
Amounts due to affiliates						27,324						4,934
Derivative instruments						16,849						45,186
Advances from joint interest owners						18,074						4,191
Other current liabilities						28,692						37,436
Total current liabilities						464,837						290,936
Long-term liabilities
Borrowings under Credit Agreement						100,000						440,000
Borrowings under San Mateo Credit Facility						385,000						334,000
Senior unsecured notes payable						1,042,580						1,040,998
Asset retirement obligations						41,689						37,919
Deferred income taxes						77,938						—
Other long-term liabilities						22,721						30,402
Total long-term liabilities						1,669,928						1,883,319
Commitments and contingencies (Note 14)
Shareholders’ equity
Common stock — $0.01 par value, 160,000,000 shares authorized; 117,861,923 and 116,847,003 shares issued; and 117,850,233 and 116,844,768 shares outstanding, respectively						1,179						1,169
Additional paid-in capital						2,077,592						2,027,069
Accumulated deficit						(171,318)						(741,705)
Treasury stock, at cost, 11,945 and 2,235 shares, respectively						(243)						(3)
Total Matador Resources Company shareholders’ equity						1,907,210						1,286,530
Non-controlling interest in subsidiaries						220,178						226,495
Total shareholders’ equity						2,127,388						1,513,025
Total liabilities and shareholders’ equity						$	4,262,153					$	3,687,280

The accompanying notes are an integral part of these consolidated financial statements.

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Matador Resources Company and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data) 

						Year Ended December 31,
						2021						2020						2019
Revenues
Oil and natural gas revenues						$	1,700,542					$	744,461					$	892,325
Third-party midstream services revenues						75,499						64,932						59,110
Sales of purchased natural gas						86,034						41,742						74,769
Lease bonus - mineral acreage						—						4,062						1,711
Realized (loss) gain on derivatives						(220,105)						38,937						9,482
Unrealized gain (loss) on derivatives						21,011						(32,008)						(53,727)
Total revenues						1,662,981						862,126						983,670
Expenses
Production taxes, transportation and processing						178,987						93,338						92,273
Lease operating						108,964						104,953						117,305
Plant and other midstream services operating						61,459						41,500						36,798
Purchased natural gas						77,126						32,734						69,398
Depletion, depreciation and amortization						344,905						361,831						350,540
Accretion of asset retirement obligations						2,068						1,948						1,822
Full-cost ceiling impairment						—						684,743						—
General and administrative						96,396						62,578						80,054
Total expenses						869,905						1,383,625						748,190
Operating income (loss)						793,076						(521,499)						235,480
Other income (expense)
Net loss on asset sales and impairment						(331)						(2,832)						(967)
Interest expense						(74,687)						(76,692)						(73,873)
Other (expense) income						(2,712)						1,864						(2,126)
Total other expense						(77,730)						(77,660)						(76,966)
Income (loss) before income taxes						715,346						(599,159)						158,514
Income tax provision (benefit)
Deferred						74,710						(45,599)						35,532
Total income tax provision (benefit)						74,710						(45,599)						35,532
Net income (loss)						640,636						(553,560)						122,982
Net income attributable to non-controlling interest in subsidiaries						(55,668)						(39,645)						(35,205)
Net income (loss) attributable to Matador Resources Company shareholders						$	584,968					$	(593,205)					$	87,777
Earnings (loss) per common share
Basic						$	5.00					$	(5.11)					$	0.75
Diluted						$	4.91					$	(5.11)					$	0.75
Weighted average common shares outstanding
Basic						116,999						116,068						116,555
Diluted						119,163						116,068						117,063

The accompanying notes are an integral part of these consolidated financial statements.

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Matador Resources Company and Subsidiaries

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(In thousands)

For the Years Ended December 31, 2021, 2020 and 2019

																																																						Total shareholders’ equity attributable to Matador Resources Company
																					Additional paid-in capital						Accumulated deficit						Treasury Stock															Non-controlling interest in subsidiaries									Total shareholders’ equity
						Common Stock
						Shares						Amount																														Shares									Amount
Balance at January 1, 2019						116,375						$	1,164																	$	1,924,408					$	(236,277)					21						$	(415)					$	1,688,880					$	90,777					$	1,779,657
Issuance of common stock pursuant to employee stock compensation plan						240						2																		(2)						—						—						—						—						—						—
Issuance of common stock pursuant to directors’ and advisors’ compensation plan						50						—																		—						—						—						—						—						—						—
Stock-based compensation expense related to equity-based awards including amounts capitalized						—						—																		23,396						—						—						—						23,396						—						23,396
Stock options exercised, net of options forfeited in net share settlements						220						2																		3,298						—						—						—						3,300						—						3,300
Liability-based stock option awards settled						1						—																		11						—						—						—						11						—						11
Restricted stock forfeited						—						—																		—						—						222						(3,691)						(3,691)						—						(3,691)
Contribution related to formation of San Mateo, net of tax of $3.1 million (See Note 6)						—						—																		11,613						—						—						—						11,613						—						11,613
Contribution of property related to formation of San Mateo II (See Note 6)						—						—																		(506)						—						—						—						(506)						506						—
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $5.9 million (See Note 6)						—						—																		22,874						—						—						—						22,874						48,510						71,384
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries						—						—																		—						—						—						—						—						(39,200)						(39,200)
Cancellation of treasury stock						(242)						(2)																		(4,078)						—						(242)						4,080						—						—						—
Current period net income						—						—																		—						87,777						—						—						87,777						35,205						122,982
Balance at December 31, 2019						116,644						1,166																		1,981,014						(148,500)						1						(26)						1,833,654						135,798						1,969,452
Issuance of common stock pursuant to employee stock compensation plan						244						2																		(2)						—						—						—						—						—						—
Issuance of common stock pursuant to directors’ and advisors’ compensation plan						85						1																		(1)						—						—						—						—						—						—
Stock-based compensation expense related to equity-based awards including amounts capitalized						—						—																		17,452						—						—						—						17,452						—						17,452
Stock options exercised, net of options forfeited in net share settlements						—						—																		(24)						—						—						—						(24)						—						(24)
Liability-based stock option awards settled in equity						22						—																		297						—						—						—						297						—						297
Restricted stock forfeited						—						—																		—						—						149						(1,489)						(1,489)						—						(1,489)
Contribution related to formation of San Mateo, net of tax of $3.1 million (See Note 6)						—						—																		11,613						—						—						—						11,613						—						11,613
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries, net of tax of $4.8 million (See Note 6)						—						—																		18,232						—						—						—						18,232						96,622						114,854
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries						—						—																		—						—						—						—						—						(45,570)						(45,570)
Cancellation of treasury stock						(148)						—																		(1,512)						—						(148)						1,512						—						—						—
Current period net (loss) income						—						—																		—						(593,205)						—						—						(593,205)						39,645						(553,560)
Balance at December 31, 2020						116,847						$	1,169																	$	2,027,069					$	(741,705)					2						$	(3)					$	1,286,530					$	226,495					$	1,513,025

																																																						Total shareholders’ equity attributable to Matador Resources Company
																					Additional paid-in capital						Accumulated deficit						Treasury Stock															Non-controlling interest in subsidiaries									Total shareholders’ equity
						Common Stock
						Shares						Amount																														Shares									Amount
Balance at January 1, 2021						116,847						$	1,169																	$	2,027,069					$	(741,705)					2						$	(3)					$	1,286,530					$	226,495					$	1,513,025
Dividends declared ($0.125 per share)						—						—																		—						(14,581)						—						—						(14,581)						—						(14,581)
Issuance of common stock pursuant to employee stock compensation plan						768						7																		(7)						—						—						—						—						—						—
Issuance of common stock pursuant to directors’ and advisors’ compensation plan						81						1																		(1)						—						—						—						—						—						—
Stock-based compensation expense related to equity-based awards including amounts capitalized						—						—																		12,113						—						—						—						12,113						—						12,113
Stock options exercised, net of options forfeited in net share settlements						312						3																		(4,258)						—						—						—						(4,255)						—						(4,255)
Restricted stock forfeited						—						—																		—						—						156						(2,621)						(2,621)						—						(2,621)
Contributions related to formation of San Mateo, net of tax of $3.6 million (See Note 6)						—						—																		45,056						—						—						—						45,056						—						45,056
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries						—						—																		—						—						—						—						—						(61,985)						(61,985)
Cancellation of treasury stock						(146)						(1)																		(2,380)						—						(146)						2,381						—						—						—
Current period net income						—						—																		—						584,968						—						—						584,968						55,668						640,636
Balance at December 31, 2021						117,862						$	1,179																	$	2,077,592					$	(171,318)					12						$	(243)					$	1,907,210					$	220,178					$	2,127,388

The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

Matador Resources Company and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

						Year Ended December 31,
						2021						2020						2019
Operating activities
Net income (loss)						$	640,636					$	(553,560)					$	122,982
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Unrealized (gain) loss on derivatives						(21,011)						32,008						53,727
Depletion, depreciation and amortization						344,905						361,831						350,540
Accretion of asset retirement obligations						2,068						1,948						1,822
Full-cost ceiling impairment						—						684,743						—
Stock-based compensation expense						9,039						13,625						18,505
Deferred income tax provision (benefit)						74,710						(45,599)						35,532
Amortization of debt issuance cost						3,659						2,832						2,484
Net loss on asset sales and impairment						331						2,832						967
Changes in operating assets and liabilities
Accounts receivable						(98,456)						53,001						(43,261)
Lease and well equipment inventory						(1,537)						(655)						4,777
Prepaid expenses and other current assets						(11,786)						(3,010)						(4,844)
Other long-term assets						56						1,681						678
Accounts payable, accrued liabilities and other current liabilities						76,891						(43,844)						(19,004)
Royalties payable						28,310						(19,144)						20,417
Advances from joint interest owners						7,018						(10,646)						3,869
Other long-term liabilities						(1,478)						(461)						2,851
Net cash provided by operating activities						1,053,355						477,582						552,042
Investing activities
Drilling, completion and equipping capital expenditures						(431,136)						(471,087)						(679,395)
Acquisition of oil and natural gas properties						(238,609)						(72,809)						(50,766)
Midstream capital expenditures						(63,359)						(234,359)						(192,035)
Expenditures for other property and equipment						(376)						(2,200)						(3,701)
Proceeds from sale of assets						4,215						4,789						21,921
Net cash used in investing activities						(729,265)						(775,666)						(903,976)
Financing activities
Repayments of borrowings under Credit Agreement						(600,000)						(35,000)						(35,000)
Borrowings under Credit Agreement						260,000						220,000						250,000
Repayments of borrowings under San Mateo Credit Facility						(84,000)						—						—
Borrowings under San Mateo Credit Facility						135,000						46,000						68,000
Cost to enter into or amend credit facilities						(4,108)						(660)						(1,443)
Proceeds from stock options exercised						1,335						45						3,300
Dividends paid						(14,581)						—						—
Contributions related to formation of San Mateo						48,626						14,700						14,700
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries						—						119,700						77,330
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries						(61,985)						(45,570)						(39,200)
Taxes paid related to net share settlement of stock-based compensation						(8,211)						(1,556)						(3,691)
Other						(629)						6,680						(918)
Net cash (used in) provided by financing activities						(328,553)						324,339						333,078
(Decrease) increase in cash and restricted cash						(4,463)						26,255						(18,856)
Cash and restricted cash at beginning of period						91,383						65,128						83,984
Cash and restricted cash at end of period						$	86,920					$	91,383					$	65,128

Supplemental disclosures of cash flow information (Note 15)

The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2021, 2020 and 2019

NOTE 1 — NATURE OF OPERATIONS

Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, the Company conducts midstream operations, primarily through its midstream joint venture, San Mateo Midstream, LLC (collectively with its subsidiaries, “San Mateo”), in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements include the accounts of Matador and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810). The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.

Restricted Cash

Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

Accounts Receivable

The Company sells its operated oil, natural gas and natural gas liquid (“NGL”) production to various purchasers (see “—Revenues” below). In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from purchasers of oil, natural gas and NGLs, participants in oil and natural gas wells for which the Company serves as the operator, San Mateo’s customers or the Company’s derivative counterparties. Accounts receivable are typically due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts.

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues associated with the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented.

For the year ended December 31, 2021, three significant purchasers accounted for 72% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (29%), Exxon Mobil Corporation (33%) and BP America Production Company (10%). For the year ended December 31, 2020, two significant purchasers accounted for 65% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (57%) and Exxon Mobil Corporation (8%). For the year ended December 31, 2019, two significant purchasers accounted for 67% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (53%) and BP America Production Company (14%). If the Company lost one or more of these significant purchasers and were unable to sell its production to other purchasers on terms it considers acceptable, it could materially and adversely affect the Company’s business, financial condition, results of operations and cash flows. At December 31, 2021, 2020 and 2019, approximately 39%, 35% and 31%, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers.

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations.

Oil and Natural Gas Properties

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $38.4 million, $30.0 million and $31.1 million of its general and administrative costs into oil and natural gas properties in 2021, 2020 and 2019, respectively. The Company capitalized $4.8 million, $5.0 million and $7.6 million of its interest expense into oil and natural gas properties for the years ended December 31, 2021, 2020 and 2019, respectively.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. For the years ended December 31, 2021, 2020 and 2019, the Company recorded depletion expense of $310.1 million, $334.8 million and $330.7 million, respectively. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of:

(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less

(d) any income tax effects related to the properties involved.

Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedge instruments for accounting purposes.

The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2021, these average oil and natural gas prices were $63.04 per Bbl and $3.60 per MMBtu, respectively. For the period from January through December 2020, these average oil and natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively. For the period from January through December 2019, these average oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials.

During the years ended December 31, 2021 and 2019, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the years ended December 31, 2021 and 2019.

For the year ended December 31, 2020, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, the Company recorded an impairment charge of $684.7 million, exclusive of tax effect, to its consolidated statement of operations for the year ended December 31, 2020 with the related deferred income tax benefit recorded net of a valuation allowance (see Note 8).

As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods.

Midstream Properties and Other Property and Equipment

Midstream properties and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and produced water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life (five to 30 years) using the straight-line method. The Company capitalized $1.3 million, $1.8 million and $1.8 million of general and administrative costs into midstream properties in 2021, 2020 and 2019, respectively. The Company did not capitalize any interest expense into midstream properties for the year ended December 31, 2021. The Company capitalized $0.5 million and $0.9 million of interest expense into midstream properties for the years ended December 31, 2020 and 2019. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream properties and other property and equipment.

The Company evaluates midstream properties and other property and equipment for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Expected future cash flows represent management’s estimates based on reasonable and supportable assumptions.

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Gains and losses associated with the disposition of midstream properties and other property and equipment are recognized as a component of other income (expense) in the consolidated statements of operations.

Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties, midstream properties or other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations.

Derivative Financial Instruments

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported as a component of revenues in the consolidated statements of operations. See Note 12 for additional information about the Company’s derivative instruments.

Revenues

The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from these contracts is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under oil and natural gas marketing contracts is typically received from the purchaser one to two months after production.

The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead or a central delivery point, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil revenues on the statements of operations, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer.

The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations.

The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”) that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract.

The Company periodically enters into natural gas purchase transactions with third parties whereby the Company (i) purchases the third party’s natural gas and subsequently sells the natural gas to other purchasers or (ii) processes the third party’s natural gas at San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of operations as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold.

From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of operations.

The following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the years ended December 31, 2021, 2020 and 2019 (in thousands).

			Year Ended December 31,
			2021						2020						2019
Revenues from contracts with customers			$	1,862,075					$	851,135					$	1,026,204
Lease bonus - mineral acreage			—						4,062						1,711
Realized (loss) gain on derivatives			(220,105)						38,937						9,482
Unrealized gain (loss) on derivatives			21,011						(32,008)						(53,727)
Total revenues			$	1,662,981					$	862,126					$	983,670

			Year Ended December 31,
			2021						2020						2019
Oil revenues			$	1,205,608					$	595,507					$	759,811
Natural gas revenues			494,934						148,954						132,514
Third-party midstream services revenues			75,499						64,932						59,110
Sales of purchased natural gas			86,034						41,742						74,769
Total revenues from contracts with customers			$	1,862,075					$	851,135					$	1,026,204

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Stock-Based Compensation

The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors and certain employees, contractors and advisors. All equity-based awards are measured at

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

fair value on the date of grant and are recognized on a straight-line basis over the awards’ vesting periods as either a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities. Awards that are expected to be settled in cash are liability-based awards, which are measured at fair value at each reporting date and are recognized over the awards’ vesting periods either as a component of general and administrative expenses in the consolidated statements of operations or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration and development activities.

The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options and the Monte Carlo simulation method to measure the fair value of performance units. The closing price of Matador’s common stock on the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”), while the closing price of Matador’s common stock on the trading day prior to the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”).

The Company’s consolidated statements of operations for the years ended December 31, 2021, 2020 and 2019 include a stock-based compensation (non-cash) expense of $9.0 million, $13.6 million and $18.5 million, respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $0.9 million, $1.0 million and $1.4 million for the years ended December 31, 2021, 2020 and 2019, respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company. The Company’s consolidated statement of operations for the years ended December 31, 2021, 2020 and 2019 also includes $20.4 million, $4.0 million and $3.2 million, respectively, related to liability-based awards expected to be settled in cash.

Income Taxes

The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized.

The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2021, 2020 and 2019, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions.

When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2021, 2020 and 2019.

Allocation of Purchase Price in Business Combinations

As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

Earnings Per Common Share

The Company reports basic earnings attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2021, 2020 and 2019 (in thousands, except per share data).

						Year Ended December 31,
						2021						2020						2019
Net income (loss) attributable to Matador Resources Company shareholders — numerator						$	584,968					$	(593,205)					$	87,777
Weighted average common shares outstanding — denominator
Basic						116,999						116,068						116,555
Dilutive effect of options and restricted stock units						2,164						—						508
Diluted weighted average common shares outstanding						119,163						116,068						117,063
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Basic						$	5.00					$	(5.11)					$	0.75
Diluted						$	4.91					$	(5.11)					$	0.75

A total of 2.5 million and 2.6 million options to purchase shares of Matador’s common stock were excluded from the diluted weighted average common shares outstanding for the years ended December 31, 2020 and 2019, respectively, because their effects were anti-dilutive. Additionally, 0.7 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2020 as the security holders do not have the obligation to share in the losses of the Company.

 Credit Risk

The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and NGL price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, the Company’s commodity derivative contracts at December 31, 2021 were with The Bank of Nova Scotia, BMO Harris Financing, Inc. (Bank of Montreal), PNC Bank and Royal Bank of Canada (or affiliates thereof), and all but BMO Harris Financing, Inc. (Bank of Montreal) were parties that are lenders (or affiliates thereof) under the Company’s reserves-based revolving credit agreement.

Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners.

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019 

NOTE 3 — PROPERTY AND EQUIPMENT

The following table presents a summary of the Company’s property and equipment balances as of December 31, 2021 and 2020 (in thousands).

						December 31,
						2021						2020
Oil and natural gas properties
Evaluated (subject to amortization)						$	6,007,325					$	5,295,931
Unproved and unevaluated (not subject to amortization)						964,714						902,133
Total oil and natural gas properties						6,972,039						6,198,064
Accumulated depletion						(3,933,355)						(3,623,265)
Net oil and natural gas properties						3,038,684						2,574,799
Midstream properties
Midstream equipment and facilities						900,979						841,695
Accumulated depreciation						(92,574)						(61,113)
Net midstream properties						808,405						780,582
Other property and equipment
Furniture, fixtures and other equipment						10,923						10,591
Software						8,225						8,116
Leasehold improvements						10,975						10,854
Total other property and equipment						30,123						29,561
Accumulated depreciation						(20,527)						(17,173)
Net other property and equipment						9,596						12,388
Net property and equipment						$	3,856,685					$	3,367,769

 The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2021 and the year in which these costs were incurred (in thousands).

Description						2021						2020						2019						2018						2017 and prior						Total
Costs incurred for
Property acquisition						$	111,120					$	40,355					$	40,140					$	417,114					$	287,666					$	896,395
Exploration wells						14,738						411						1,199						123						274						16,745
Development wells						46,232						2,027						3,245						60						10						51,574
Total						$	172,090					$	42,793					$	44,584					$	417,297					$	287,950					$	964,714

Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions.

Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2021 are related to the Company’s leasehold and mineral acquisitions in the Delaware Basin in Southeast New Mexico and West Texas. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base.

Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $68.3 million at December 31, 2021. Of this total, $16.7 million was associated with exploration wells and $51.6 million was associated with development wells. The

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 3 — PROPERTY AND EQUIPMENT — Continued

Company anticipates that most of the $68.3 million associated with these wells in progress at December 31, 2021 will be transferred to the amortization base during 2022. Unproved and unevaluated property costs for exploration and development wells incurred in years prior to 2021 are costs related to the advanced preparation for wells that the Company intends to drill in the future.

NOTE 4 — LEASES

The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability, and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheets. The Company elected to include payments for non-lease components associated with certain leases when determining the present value of the lease payments. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rates used for the year ended December 31, 2021 were 2.73% and 1.99% for operating leases and financing leases, respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheets unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets.

The following table presents supplemental consolidated statement of operations information related to lease expenses, on a gross basis, for the years ended December 31, 2021 and 2020, respectively (in thousands). Lease payments represent gross payments to vendors, which, for certain of the Company’s operating assets, are partially offset by amounts received from other working interest owners in the Company’s operated wells.

									Year Ended December 31,
									2021						2020
Operating leases
Lease operating									$	11,393					$	12,994
Plant and other midstream services									36						28
General and administrative									3,645						3,698
Total operating leases(1)									15,074						16,720
Short-term leases
Lease operating									11,234						12,890
Plant and other midstream services									4,037						5,689
General and administrative									37						47
Total short-term leases(2)(3)									15,308						18,626
Financing leases
Depreciation of assets									566						747
Interest on lease liabilities									138						123
Total financing leases									704						870
Total lease expense									$	31,086					$	36,216

_____________________

(1)     Does not include gross payments related to drilling rig leases of $31.9 million and $33.6 million for the years ended December 31, 2021 and 2020, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2021 and 2020, respectively.

(2)    These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheets as they are short-term leases.

(3)    Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $61.7 million and $65.3 million for the years ended December 31, 2021 and 2020, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2021 and 2020, respectively.

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 4 — LEASES — Continued

The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2021 and 2020, respectively (in thousands).

						December 31,
						2021						2020
Operating leases
Other long-term assets						$	29,519					$	51,528
Other current liabilities						$	(19,649)					$	(35,716)
Other long-term liabilities						(15,340)						(21,598)
Total operating lease liabilities						$	(34,989)					$	(57,314)
Financing leases
Other property and equipment, at cost						$	5,914					$	3,673
Accumulated depreciation						(3,485)						(2,134)
Net property and equipment						$	2,429					$	1,539
Other current liabilities						$	(378)					$	(621)
Other long-term liabilities						(45)						(256)
Total financing lease liabilities						$	(423)					$	(877)

The following table presents supplemental consolidated cash flow information related to lease payments for the year ended December 31, 2021 and 2020, respectively (in thousands).

						Year Ended December 31,
						2021						2020
Cash paid related to lease liabilities
Operating cash payments for operating leases						$	14,430					$	15,664
Investing cash payments for operating leases						$	31,967					$	33,556
Financing cash payments for financing leases						$	629					$	790
Right of use assets obtained in exchange for lease obligations entered into during the period
Operating leases						$	18,454					$	12,474
Financing leases						$	2,241					$	996

The following table presents the maturities of lease liabilities at December 31, 2021 (in years).

Weighted-Average Remaining Lease Term						December 31, 2021
Operating leases						2.5
Financing leases						1.7

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 4 — LEASES — Continued

The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2021 (in thousands). 

						December 31, 2021
						Operating Leases						Financing Leases
2022						$	19,649					$	378
2023						6,830						180
2024						4,217						37
2025						4,287						—
2026						1,553						—
Thereafter						—						—
Total lease payments						36,536						595
Less imputed interest						(1,547)						(172)
Total lease obligations						34,989						423
Less current obligations						(19,649)						(378)
Long-term lease obligations						$	15,340					$	45

NOTE 5 — ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations primarily relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability.

The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2021 and 2020 (in thousands). 

						Year Ended December 31,
						2021						2020
Beginning asset retirement obligations						$	38,542					$	36,211
Liabilities incurred during period						2,294						2,548
Liabilities settled during period						(151)						(290)
Revisions in estimated cash flows						86						(1,875)
Divestitures during the period						(880)						—
Accretion expense						2,068						1,948
Ending asset retirement obligations						41,959						38,542
Less: current asset retirement obligations(1)						(270)						(623)
Long-term asset retirement obligations						$	41,689					$	37,919

__________________

(1)Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2021 and 2020.

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Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES

Business Combination

On December 14, 2021, the Company completed an acquisition of assets from a private operator. This acquisition was accounted for as a business combination in accordance with ASC Topic 805, which requires the assets acquired and liabilities assumed to be recorded at fair value as of the respective acquisition date. The Company obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, strategically located primarily within the Company’s existing acreage in its Ranger and Arrowhead asset areas.

As consideration for the business combination, the Company paid approximately $161.7 million in cash and will pay an additional $6.5 million, net of customary working capital adjustments, including adjusting for production, revenues, operating expenses and capital expenditures from August 1, 2021 to closing. In addition, the Company will increase the purchase price by $5.0 million for each quarter during 2022 in which the average oil price, as defined in the purchase and sale agreement, is greater than $75.00 per barrel. The Company recorded this contingent consideration at fair value on the date of the business combination and will record the change in the fair value in future periods as “Other income (expense)” in its consolidated statements of operations. The fair value of the contingent consideration increased between December 14, 2021 and December 31, 2021 by $1.5 million, which was recorded as “Other expense” for the year ended December 31, 2021. The Company used the Monte Carlo simulation method to measure the fair value of the contingent consideration, which has unobservable inputs and is thus classified at Level 3 in the fair value hierarchy (see Note 13 for discussion of the fair value hierarchy).

In addition, the Company acquired oil and natural gas production of approximately 3,500 BOE per day at the date of acquisition, which increased the Company’s revenues and net income for the period from December 15, 2021 through December 31, 2021 by $4.0 million and $3.2 million, respectively. The pro forma impact of this business combination to revenues and net income for the remainder of 2021 would not be material to the Company’s 2021 revenues and net income as reported.

The preliminary allocation of the consideration given related to this business combination was as follows (in thousands). The Company anticipates that the allocation of the consideration given should be finalized during 2022 upon determination of the final customary purchase price adjustments.

Consideration given			Allocation
Cash			$161,680
Working capital adjustments to be paid in 2022			6,500
Fair value of contingent consideration at December 14, 2021			6,718
Total consideration given			$174,898
Allocation of purchase price
Oil and natural gas properties
Evaluated			$139,312
Unproved and unevaluated			43,204
Accrued liabilities			(360)
Advances from joint interest owners			(6,865)
Asset retirement obligations			(393)
Net assets acquired			$174,898

Joint Ventures

At December 31, 2021, the Company owned 51% of San Mateo, a midstream joint venture with a subsidiary of Five Point Energy LLC (“Five Point”) in portions of Eddy County, New Mexico and Loving County, Texas. At December 31, 2021, Five Point owned the remaining 49% of San Mateo. The midstream assets include (i) the Black River Processing Plant, (ii) 14 salt water disposal wells and associated commercial salt water disposal facilities and (iii) approximately 370 miles of oil gathering and transportation pipelines, natural gas gathering pipelines and produced water pipelines. The Company operates San Mateo, and San Mateo is consolidated in the Company’s financial statements, with Five Point’s interest being accounted for as a non-controlling interest.

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued

As part of the joint venture agreement with Five Point, the Company had the potential to earn two different sets of performance incentives. These performance incentives are recorded as additional contributions related to the formation of San Mateo as they are received. Beginning in 2017, the Company had the potential to earn up to $73.5 million in performance incentives related to the Company’s performance in its Rustler Breaks asset area in Eddy County and its Wolf asset area in Loving County over a five-year period, which in October 2020 was extended by an additional year to January 31, 2023. At December 31, 2021, the Company had earned $58.8 million of the potential $73.5 million in performance incentives and Five Point had paid $14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020 and 2021. The Company may earn up to the remaining $14.7 million in performance incentives until January 31, 2023. Beginning in 2019, the Company had the potential to earn up to $150.0 million in additional deferred performance incentives in its Stebbins area and surrounding leaseholds in the southern portion of its Arrowhead asset area (the “Greater Stebbins Area”) and Stateline asset area over the next several years, plus additional performance incentives for securing volumes from third-party customers. During the year ended December 31, 2021, Five Point paid $33.9 million in these additional performance incentives.

The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements (see Note 14).

During the years ended December 31, 2021 and 2020, San Mateo distributed $64.5 million and $47.4 million, respectively, to the Company and $62.0 million and $45.6 million, respectively, to Five Point. During the year ended December 31, 2021, neither the Company nor Five Point contributed cash to San Mateo. During the year ended December 31, 2020, the Company contributed $75.0 million and Five Point contributed $119.7 million of cash to San Mateo, of which $23.1 million was paid to carry Matador’s proportionate interest in San Mateo Midstream II, LLC (“San Mateo II”). Five Point agreed to carry a portion of Matador’s proportionate interest as part of the formation agreement for San Mateo II. The amount that Five Point paid to carry Matador’s proportionate interest in San Mateo was recorded in “Additional paid-in capital” in the Company’s consolidated balance sheets at December 31, 2020, net of the $4.8 million deferred tax impact to Matador related to this equity contribution. During the year ended December 31, 2019, the Company contributed $24.2 million and Five Point contributed $77.3 million of cash to San Mateo, of which $28.4 million was paid to carry Matador’s proportionate interest in San Mateo II and was recorded in “Additional paid-in capital” in the consolidated balance sheet, net of the $5.9 million deferred tax impact to Matador related to this equity contribution. In the first quarter of 2019, the Company also contributed $1.0 million of property to San Mateo II. San Mateo II was merged with and into San Mateo effective October 1, 2020.

Divestitures    

During 2021 and 2020, the Company converted approximately $4.2 million and $4.8 million, respectively, of non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana.

NOTE 7 — DEBT

At December 31, 2021, the Company had (i) $1.05 billion of outstanding senior notes due 2026, (ii) $100.0 million in borrowings outstanding under its reserves-based revolving credit facility, (iii) approximately $45.8 million in outstanding letters of credit issued pursuant to its revolving credit facility and (iv) $7.5 million outstanding under an unsecured U.S. Small Business Administration loan.

At December 31, 2021, San Mateo had $385.0 million in borrowings outstanding under its revolving credit facility and approximately $9.0 million in outstanding letters of credit issued pursuant to its revolving credit facility.

Credit Agreements

MRC Energy Company

On November 18, 2021, the Company entered into its Fourth Amended and Restated credit facility with the lenders party thereto, led by Royal Bank of Canada (“RBC”) as administrative agent (the “Credit Agreement”). MRC Energy Company (“MRC”), a subsidiary of Matador that directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 85% of MRC’s and the Restricted Subsidiaries’ (as defined in the Credit Agreement) proved oil and natural gas properties and by the equity interests of certain of MRC’s wholly-owned subsidiaries, which are also guarantors. San Mateo and its subsidiaries are not guarantors of the Credit Agreement. In addition, all obligations under the

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Table of Contents

Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 7 — DEBT — Continued

Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC. The Credit Agreement matures on October 31, 2026 or, if earlier, the date that is 180 days prior to the earliest stated redemption date of any senior notes of the Company with an outstanding principal balance in excess of $25.0 million.

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates.

In November 2021, the lenders completed their review of the Company’s proved oil and natural gas reserves, and, as a result, the borrowing base was increased from $900.0 million to $1.35 billion. The Company elected to keep the borrowing commitment at $700.0 million, and the maximum facility amount remained $1.5 billion. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below).

In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at such time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months.

Total deferred loan costs were $3.9 million at December 31, 2021, and these costs are being amortized over the term of the Credit Agreement. The Company’s effective interest rate under the Credit Agreement was 1.85% at December 31, 2021. At December 31, 2021, the Company had $100.0 million in borrowings outstanding under the Credit Agreement and approximately $45.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. Between December 31, 2021 and February 28, 2022, the Company repaid $25.0 million of borrowings outstanding under the Credit Agreement.

Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If MRC borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50%, and (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount ranging from 0.75% to 1.75% per annum depending on the level of borrowings under the Credit Agreement. If MRC borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the LIBOR Rate (as defined in the Credit Agreement) plus (y) an amount ranging from 1.75% to 2.75% per annum depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, three or six months as designated by MRC. If MRC has outstanding borrowings under the Credit Agreement and interest rates increase, so will MRC’s interest costs, which may have a material adverse effect on the Company’s results of operations and financial condition.

A commitment fee of 0.375% to 0.50% per annum, depending on the level of borrowings under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75 million of cash or cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less.

Subject to certain exceptions, the Credit Agreement contains various covenants that limit MRC’s and its Restricted Subsidiaries’ (as defined in the Credit Agreement) ability to take certain actions, including, but not limited to, the following:

•incur indebtedness or grant liens on any of its assets;

•enter into commodity hedging agreements or interest rate agreements;

•declare or pay dividends, distributions or redemptions;

•merge or consolidate;

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 7 — DEBT — Continued

•make any loans or investments;

•engage in transactions with affiliates;

•engage in certain asset dispositions, including a sale of all or substantially all of MRC’s assets; and

•take certain actions with respect to the Company’s senior unsecured notes.

If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events:

•failure to pay any principal on the outstanding borrowings when due or any interest on the outstanding borrowings, any reimbursement obligation under any letter of credit or any fees or other amounts within certain grace periods;

•failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;

•bankruptcy or insolvency events involving the Company or any of the Restricted Subsidiaries; and

•a change of control, as defined in the Credit Agreement.

The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2021.

San Mateo Midstream, LLC

On December 19, 2018, San Mateo entered into a $250.0 million credit facility with the lenders party thereto, currently led by Truist Bank as administrative agent (the “San Mateo Credit Facility”). The San Mateo Credit Facility matures December 19, 2023 and was amended in June 2021 to increase the lender commitments under the revolving credit facility from $375.0 million to $450.0 million (subject to San Mateo’s compliance with the covenants noted below) and to increase the borrowing rate for a base rate loan or a Eurodollar loan under such facility by 0.50%. The San Mateo Credit Facility includes an accordion feature, which, after the aforementioned amendment, provides for potential increases in lender commitments to up to $700.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property.

Total deferred loan costs were $1.9 million at December 31, 2021, and these costs are being amortized over the term of the San Mateo Credit Facility. San Mateo’s effective interest rate under the San Mateo Credit Facility was 2.11% at December 31, 2021. At December 31, 2021, San Mateo had $385.0 million in borrowings outstanding under the San Mateo Credit Facility and $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. Between December 31, 2021 and February 22, 2022, San Mateo repaid $30.0 million of borrowings outstanding under the San Mateo Credit Facility.

Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a Eurodollar loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50%, and (iii) the Adjusted LIBO Rate (as defined in the San Mateo Credit Facility) plus 1.0% plus, in each case, an amount ranging from 1.00% to 2.00% per annum depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (x) the Adjusted LIBO Rate for the chosen interest period plus (y) an amount ranging from 2.00% to 3.00% per annum depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition.

A commitment fee of 0.30% to 0.50% per annum, depending on the unused availability under the San Mateo Credit Facility, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense, of 2.50 or more. The San Mateo Credit Facility also restricts the ability

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 7 — DEBT — Continued

of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility.

Subject to certain exceptions, the San Mateo Credit Facility contains various covenants that limit San Mateo’s and its restricted subsidiaries’ ability to take certain actions, including, but not limited to, the following:

•incur indebtedness or grant liens on any of San Mateo’s assets;

•enter into hedging agreements;

•declare or pay dividends, distributions or redemptions;

•merge or consolidate;

•make any loans or investments;

•engage in transactions with affiliates;

•engage in certain asset dispositions, including a sale of all or substantially all of San Mateo’s assets; and

•issue equity interests in San Mateo or its subsidiaries.

If an event of default exists under the San Mateo Credit Facility, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events:

•failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods;

•failure to perform or otherwise comply with the covenants and obligations in the San Mateo Credit Facility or other loan documents, subject, in certain instances, to certain grace periods;

•bankruptcy or insolvency events involving San Mateo or its subsidiaries; and

•a change of control, as defined in the San Mateo Credit Facility.

The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2021.

Senior Unsecured Notes

At December 31, 2021, the Company had $1.05 billion of outstanding 5.875% senior notes due 2026 that were registered under the Securities Act and mature September 15, 2026 (the “Notes”). Interest is payable on the Notes semi-annually in arrears on each March 15 and September 15. The Notes are guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo and its subsidiaries are not Restricted Subsidiaries (as defined in the Indenture) or Guarantors of the Notes.

The Company may redeem all or a part of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on September 15 of the years indicated below:

Year						Redemption Price
2021						104.406%
2022						102.938%
2023						101.469%
2024 and thereafter						100.000%

Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following:

•incur additional indebtedness;

•sell assets;

•pay dividends or make certain investments;

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Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 7 — DEBT — Continued

•create liens that secure indebtedness;

•enter into transactions with affiliates; and

•merge or consolidate with another company.

In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the Indenture) that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events:

•default for 30 days in the payment when due of interest on the Notes;

•default in the payment when due of the principal of, or premium, if any, on the Notes;

•failure by the Company to comply with its obligations to offer to purchase or purchase Notes pursuant to the change of control or asset sale covenants of the Indenture or to comply with the covenant relating to mergers;

•failure by the Company for 180 days after notice to comply with its reporting obligations under the Indenture;

•failure by the Company for 60 days after notice to comply with any of the other agreements in the Indenture;

•payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $50.0 million or more;

•failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $50.0 million within 60 days;

•any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and

•certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

The outstanding borrowings of $100.0 million at December 31, 2021 under the Credit Agreement mature on October 31, 2026. The outstanding borrowings of $385.0 million at December 31, 2021 under the San Mateo Credit Facility mature on December 19, 2023. The $1.05 billion of outstanding Notes at December 31, 2021 mature on September 15, 2026.

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Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2020, 2019 and 2018

NOTE 8 — INCOME TAXES

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2021 and 2020 is as follows (in thousands).

						December 31,
						2021						2020
Deferred tax assets
Net operating loss carryforwards						$	129,651					$	122,952
Unrealized loss on derivatives						3,729						8,997
Percentage depletion carryover						1,770						1,462
Compensation						9,838						10,405
Lease liabilities						4,866						9,380
Other						9,410						8,334
Total deferred tax assets						159,264						161,530
Valuation allowance on deferred tax assets						(10,599)						(110,681)
Total deferred tax assets, net of valuation allowance						148,665						50,849
Deferred tax liabilities
Property and equipment						(179,153)						(11,879)
Less than wholly-owned subsidiaries						(39,900)						(26,564)
Lease right of use assets						(4,866)						(9,380)
Other						(2,684)						(2,684)
Total deferred tax liabilities						(226,603)						(50,507)
Net deferred tax (liabilities) assets						$	(77,938)					$	342

At December 31, 2021, the Company had net operating loss carryforwards of $555.2 million for federal income tax purposes and $223.3 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning in 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards begin expiring at various dates beginning in 2024; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027.

At December 31, 2020, the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by impairment charges recorded in 2020. As a result, the Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2020. The remaining net deferred tax asset at December 31, 2020 relates to state taxes, for which the deferred taxes were determined to be more likely than not to be utilized. Due to a variety of factors, including the Company’s significant net income in 2021, the Company’s federal valuation allowance was reversed as of September 30, 2021 as the deferred tax assets were determined to be more likely than not to be utilized. As a portion of the Company’s state net operating loss carryforwards are not expected to be utilized before expiration, a valuation allowance will continue to be recognized until the state deferred tax assets are more likely than not to be utilized.

The current income tax provision and the deferred income tax provision for the years ended December 31, 2021, 2020 and 2019 were comprised of the following (in thousands). 

						Year Ended December 31,
						2021						2020						2019
Deferred income tax provision (benefit)
Federal income tax						$	44,883					$	(25,675)					$	29,171
State income tax						29,827						(19,924)						6,361
Net deferred income tax provision (benefit)						$	74,710					$	(45,599)					$	35,532

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Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 8 — INCOME TAXES — Continued

Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax provision (benefit) for the years ended December 31, 2021, 2020 and 2019 is as follows (in thousands). 

						Year Ended December 31,
						2021						2020						2019
Federal tax expense (benefit) at statutory rate(1)						$	150,223					$	(125,823)					$	33,441
State income tax						26,646						(20,607)						6,141
Permanent differences						(2,078)						(3,114)						(4,267)
Change in federal valuation allowance						(103,262)						103,262						—
Change in state valuation allowance						3,181						683						217
Net deferred income tax provision (benefit)						74,710						(45,599)						35,532
Total income tax provision (benefit)						$	74,710					$	(45,599)					$	35,532

__________________    

(1)The statutory federal tax rate was 21% for the years ended December 31, 2021, 2020 and 2019.

The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2018. The earliest tax year open for examination for the State of Texas tax return is 2017.

The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2021, the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions.

NOTE 9 — STOCK-BASED COMPENSATION

Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards

In 2012, the Company’s Board of Directors adopted and shareholders approved the 2012 Incentive Plan. The 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that could be issued pursuant to options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants.

In 2019, the Company’s Board of Directors adopted and shareholders approved the 2019 Incentive Plan. As of December 31, 2021, the 2019 Incentive Plan provided for a maximum of 1,571,972 shares of common stock in the aggregate that may be issued pursuant to grants of options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. The persons eligible to receive awards under the 2019 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2019 Incentive Plan is to attract and retain key employees, directors, contractors or advisors of the Company. With the adoption of the 2019 Incentive Plan, the Company does not expect to make any future awards under the 2012 Incentive Plan, but the 2012 Incentive Plan will remain in place until all awards outstanding under that plan have been settled.

The 2012 Incentive Plan and the 2019 Incentive Plan are administered by the independent members of the Board of Directors, who, upon recommendation of the Strategic Planning and Compensation Committee of the Board of Directors, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants.

During the years ended December 31, 2021, 2020 and 2019, the Company granted both equity-based and liability-based awards under the 2019 Incentive Plan. The fair value of equity-based awards is fixed at the grant date, while the fair value of liability-based awards is remeasured at each reporting period.

Stock Options

Under the 2012 Incentive Plan and the 2019 Incentive Plan, stock option awards have been granted and are outstanding to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five, six or 10 years. The 2012 Incentive Plan defines fair market value as the closing price of Matador’s common stock on the date of grant. Under the 2019 Incentive Plan, such fair market value of a stock option is determined using the closing price of Matador’s common stock on the trading day prior to the date of grant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 9 — STOCK-BASED COMPENSATION — Continued

The weighted average grant date fair value for stock option awards granted under the 2019 Incentive Plan was estimated using the following weighted average assumptions during the year ended December 31, 2019. The Company did not grant stock option awards during the years ended December 31, 2021 and 2020.

												2019
Stock option pricing model												Black Scholes Merton
Expected option life												4.00 years
Risk-free interest rate												1.46%
Volatility												48.52%
Dividend yield												—%
Estimated forfeiture rate												4.43%
Weighted average fair value of stock option awards granted during the year												$5.04

The Company estimated the future volatility of its common stock using the historical value of its stock for a period of time commensurate with the expected term of the stock option. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate was the rate for constant yield U.S. Treasury securities with a term to maturity that was consistent with the expected term of the award.

Summarized information about stock options outstanding at December 31, 2021 under the 2012 Incentive Plan and the 2019 Incentive Plan (collectively, the “LTIPs”) is as follows.

						Number of options (in thousands)						Weighted average exercise price
Options outstanding at December 31, 2020						2,473						$	23.08
Options granted						—						$	—
Options exercised						(1,368)						$	25.37
Options forfeited						(37)						$	18.72
Options expired						(465)						$	16.90
Options outstanding at December 31, 2021						603						$	22.92

						Options outstanding at December 31, 2021																		Options exercisable at December 31, 2021
Range of exercise prices						Shares outstanding (in thousands)						Weighted average remaining contractual life						Weighted average exercise price						Shares exercisable (in thousands)						Weighted average exercise price
$14.48 - $15.40						240						3.66						$	14.80					82						$	14.80
$26.86 - $29.68						363						1.59						$	28.28					363						$	28.28

At December 31, 2021, the aggregate intrinsic value for both outstanding and exercisable options was $4.9 million, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The remaining weighted average contractual term of exercisable options at December 31, 2021 was 1.97 years.

The total intrinsic value of options exercised during the years ended December 31, 2021, 2020 and 2019 was $15.8 million, $0.3 million and $0.8 million, respectively. The tax related benefit realized from the exercise of stock options totaled $16.8 million, $1.4 million and $2.8 million for the years ended December 31, 2021, 2020 and 2019, respectively.

At December 31, 2021, the total remaining unrecognized compensation expense related to unvested stock options was approximately $0.5 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 0.66 years.

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Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 9 — STOCK-BASED COMPENSATION — Continued

The fair value of options vested during 2021, 2020 and 2019 was $3.0 million, $6.7 million and $9.7 million, respectively.

Service-Based Restricted Stock, Restricted Stock Units and Common Stock

The Company has granted stock, restricted stock and restricted stock unit awards to employees, consultants, outside directors and advisors of the Company under the LTIPs. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The equity-based restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Liability-based restricted stock units are settled in cash upon vesting. Restricted stock and restricted stock units granted in 2021, 2020 and 2019 were service-based awards, which will settle in cash or equity, and vest over a one-year to three-year period. Performance-based restricted stock units granted in 2021 and 2020 vest in an amount between zero and 200% of the target units granted based on the Company’s relative total shareholder return over the three-year periods ending December 31, 2023 and 2022, respectively, as compared to a designated peer group, and will be settled in equity.

Equity-Based

A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2021 is presented below (in thousands, except fair value).

						Restricted Stock												Restricted Stock Units
						Service Based																								Service Based												Performance Based
Non-vested restricted stock and restricted stock units						Shares						Weighted average fair value																		Shares						Weighted average fair value						Shares						Weighted average fair value
Non-vested at December 31, 2020						682						$	20.01																	75						$	8.85					1,069						$	9.05
Granted						283						$	37.56																	36						$	30.97					366						$	50.53
Vested(1)						(334)						$	27.14																	(78)						$	9.02					(397)						$	20.00
Forfeited						(42)						$	17.35																	—						$	—					(75)						$	9.33
Non-vested at December 31, 2021						589						$	24.59																	33						$	33.39					963						$	20.26

__________________    

(1)On December 31, 2021, 396,827 of the performance-based awards that were granted in 2019 vested. The vested units earned 200% for each vested award representing 793,654 aggregate shares of common stock, which were issued on December 31, 2021.

Liability-Based

A summary of the non-vested liability-based restricted stock units as of December 31, 2021 is presented below (in thousands).

Non-vested restricted stock units																														Shares
Non-vested at December 31, 2020																														1,319
Granted																														357
Vested																														(487)
Forfeited																														(87)
Non-vested at December 31, 2021																														1,102

The Company settled 487,252 liability-based awards for $12.4 million and 226,363 liability-based awards for $2.4 million in cash for the years ended December 31, 2021 and 2020, respectively. The Company did not settle any liability awards for the year ended December 31, 2019.

At December 31, 2021, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $99.2 million, of which $40.7 million is expected to be settled in cash as calculated based on the maximum number of shares of restricted stock units vesting, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 9 — STOCK-BASED COMPENSATION — Continued

At December 31, 2021, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $50.3 million, of which $24.0 million is expected to be settled in cash, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 2.0 years.

The fair value of restricted stock and restricted stock units vested during 2021, 2020 and 2019 was $51.9 million, $8.4 million and $13.6 million, respectively.

Summary

During the years ended December 31, 2021, 2020 and 2019, the total expense attributable to stock options was $1.0 million, $3.4 million and $6.4 million, respectively. During the years ended December 31, 2021, 2020 and 2019, the total expense attributable to restricted stock and restricted stock units was $36.3 million, $17.7 million and $20.2 million, respectively. During the years ended December 31, 2021, 2020 and 2019, the Company capitalized $7.2 million, $3.6 million and $5.0 million, respectively, related to stock-based compensation and expensed the remaining $30.0 million, $17.6 million and $21.6 million, respectively.

The total tax benefit recognized for all stock-based compensation was $7.9 million, $4.5 million and $5.6 million for the years ended December 31, 2021, 2020 and 2019, respectively.

NOTE 10 — EMPLOYEE BENEFIT PLANS

401(k) Plan

All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan that equals 3% of the employee’s annual compensation, up to the maximum allowable under the Internal Revenue Code, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $1.6 million, $1.4 million and $1.4 million in 2021, 2020 and 2019, respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $2.1 million, $1.8 million and $1.7 million in 2021, 2020 and 2019, respectively. The Company made no additional contributions in any reporting period presented.

NOTE 11 — EQUITY

Common Stock Dividend

The Company’s Board of Directors (the “Board”) declared a quarterly cash dividend of $0.025 per share of common stock in each of the first three quarters of 2021 and, in October 2021, the Board amended the Company’s dividend policy to increase the quarterly dividend and declared a quarterly cash dividend of $0.05 per share of common stock. Total cash dividends declared and paid totaled $14.6 million during the year ended December 31, 2021. There were no cash dividends declared or paid prior to 2021.

Treasury Stock

On October 21, 2021, October 22, 2020 and October 24, 2019, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2021, 2020 and 2019, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company.

The shares of treasury stock outstanding at December 31, 2021, 2020 and 2019 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees.

Preferred Stock

The Company’s Amended and Restated Certificate of Formation authorizes 2,000,000 shares of preferred stock. Before any such shares are issued, the Board of Directors shall fix and determine the designations, preferences, limitations and relative rights, including voting rights of the shares of each such series.

NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company records derivative financial instruments on its consolidated

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments.

At December 31, 2021, the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling for the collars and fixed price for the swaps. At December 31, 2021, each contract was set to expire at varying times during 2022. The Company had no open contracts associated with NGL prices at December 31, 2021.

 The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2021.

												Notional Quantity (Bbl or MMBtu)						Weighted Average Price Floor ($/Bbl or $/MMBtu)						Weighted Average Price Ceiling ($/Bbl or $/MMBtu)						Fair Value of Asset (Liability) (thousands)
Commodity						Calculation Period
Oil						01/01/2022 - 12/31/2022						2,040,000						$	50.00					$	67.85					$	(16,652)
Natural Gas						01/01/2022 - 03/31/2022						8,250,000						$	2.70					$	6.33					(151)
Total open costless collar contracts																														$	(16,803)

The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2021.

Commodity						Calculation Period						Notional Quantity (Bbl)						Fixed Price ($/Bbl)						Fair Value of Asset (Liability) (thousands)
Oil Basis						01/01/2022 - 12/31/2022						5,520,000						$	0.95					1,925
Total open basis swap contracts																								$	1,925

At December 31, 2021, the Company had an aggregate net liability value for open derivative financial instruments of $14.9 million.

The Company’s derivative financial instruments are subject to master netting arrangements, and the Company’s counterparties allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2021 and December 31, 2020 (in thousands).

Derivative Instruments						Gross amounts recognized						Gross amounts netted in the consolidated balance sheets						Net amounts presented in the consolidated balance sheets
December 31, 2021
Current assets						$	215,145					$	(213,174)					$	1,971
Current liabilities						(230,023)						213,174						(16,849)
Total						$	(14,878)					$	—					$	(14,878)
December 31, 2020
Current assets						$	382,328					$	(375,601)					$	6,727
Other assets						150,194						(147,624)						2,570
Current liabilities						(420,787)						375,601						(45,186)
Long-term liabilities						(147,624)						147,624						—
Total						$	(35,889)					$	—					$	(35,889)

The following table summarizes the location and aggregate gain (loss) of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands).

												Year Ended December 31,
Type of Instrument						Location in Statements of Operations						2021						2020						2019
Derivative Instrument
Oil						Revenues: Realized (loss) gain on derivatives						$	(194,058)					$	38,937					$	9,026
Natural Gas						Revenues: Realized (loss) gain on derivatives						(26,047)						—						456
Realized (loss) gain on derivatives												(220,105)						38,937						9,482
Oil						Revenues: Unrealized gain (loss) on derivatives						26,857						(37,703)						(53,443)
Natural Gas						Revenues: Unrealized (loss) gain on derivatives						(5,846)						5,695						(284)
Unrealized gain (loss) on derivatives												21,011						(32,008)						(53,727)
Total												$	(199,094)					$	6,929					$	(44,245)

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Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 13 — FAIR VALUE MEASUREMENTS

The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories.

Level 1    Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets.

Level 2    Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs, including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

Level 3    Unobservable inputs that are not corroborated by market data that reflect a company’s own market assumptions.

Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2021 and 2020 (in thousands). 

						Fair Value Measurements at December 31, 2021 using
Description
						Level 1						Level 2						Level 3						Total
Assets (Liabilities)
Oil derivatives and basis swaps						$	—					$	(14,727)					$	—					$	(14,727)
Natural gas derivatives						—						(151)						—						(151)
Contingent consideration related to business combination						—						—						(8,203)						(8,203)
Total						$	—					$	(14,878)					$	(8,203)					$	(23,081)

						Fair Value Measurements at December 31, 2020 using
Description
						Level 1						Level 2						Level 3						Total
Assets (Liabilities)
Oil derivatives and basis swaps						$	—					$	(41,584)					$	—					$	(41,584)
Natural gas derivatives						—						5,695						—						5,695
Total						$	—					$	(35,889)					$	—					$	(35,889)

Additional disclosures related to derivative financial instruments are provided in Note 12.

Other Fair Value Measurements

 At December 31, 2021 and 2020, the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners and other current liabilities approximated their fair values due to their short-term maturities.

At December 31, 2021 and 2020, the carrying value of borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy.

At December 31, 2021 and 2020, the fair value of the Notes was $1.08 billion and $1.03 billion, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 13 — FAIR VALUE MEASUREMENTS — Continued

Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination, lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2021 and 2020.

NOTE 14 — COMMITMENTS AND CONTINGENCIES

Processing, Transportation and Produced Water Disposal Commitments

Firm Commitments    

From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and produced water from certain portions of its acreage for gathering, transportation, processing, fractionation, sales and disposal. The Company paid approximately $48.7 million and $46.0 million for deliveries under these agreements during the years ended December 31, 2021 and 2020, respectively. Certain of these agreements contain minimum volume commitments. If the Company does not meet the minimum volume commitments under these agreements, it will be required to pay certain deficiency fees. If the Company ceased operations in the areas subject to these agreements at December 31, 2021, the total deficiencies required to be paid by the Company under these agreements would be approximately $597.3 million.

San Mateo Commitments

The Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas and acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, the Company dedicated to San Mateo its current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements (collectively with the transportation, gathering and produced water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The remaining minimum contractual obligation under the Operational Agreements at December 31, 2021 was approximately $390.3 million.

Other Commitments

The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $10.8 million at December 31, 2021.

At December 31, 2021, the Company had outstanding commitments to drill and complete and to participate in the drilling and completion of various operated and non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s undiscounted minimum outstanding aggregate commitments for its participation in these operated and non-operated wells were approximately $65.4 million at December 31, 2021. The Company expects these costs to be incurred within the next three years.

Legal Proceedings

The Company is a party to several legal proceedings encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 15 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at December 31, 2021 and 2020 (in thousands).

						December 31,
						2021						2020
Accrued evaluated and unproved and unevaluated property costs						$	128,598					$	44,012
Accrued midstream properties costs						7,799						12,776
Accrued lease operating expenses						32,182						24,276
Accrued interest on debt						18,232						18,315
Accrued asset retirement obligations						270						623
Accrued partners’ share of joint interest charges						17,460						7,407
Accrued payable related to purchased natural gas						11,284						418
Other						37,458						11,331
Total accrued liabilities						$	253,283					$	119,158

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2021, 2020 and 2019 (in thousands).

						Year Ended December 31,
						2021						2020						2019
Cash paid for interest expense, net of amounts capitalized						$	74,843					$	76,880					$	75,525
Increase (decrease) in asset retirement obligations related to mineral properties						$	1,091					$	(208)					$	2,912
Increase in asset retirement obligations related to midstream properties						$	257					$	690					$	1,204
Increase (decrease) in liabilities for drilling, completion and equipping capital expenditures						$	80,255					$	(26,126)					$	(13,310)
Increase (decrease) increase in liabilities for acquisition of oil and natural gas properties						$	2,981					$	(2,346)					$	(2,567)
(Decrease) increase in liabilities for midstream capital expenditures						$	(4,478)					$	(33,609)					$	30,374
Stock-based compensation expense recognized as liability						$	24,494					$	3,702					$	3,170
Transfer of inventory (to) from oil and natural gas properties						$	(398)					$	608					$	1,515

The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance sheets to cash and restricted cash as presented on the consolidated statements of cash flows (in thousands).

						Year Ended December 31,
						2021						2020						2019
Cash						$	48,135					$	57,916					$	40,024
Restricted cash						38,785						33,467						25,104
Total cash and restricted cash						$	86,920					$	91,383					$	65,128

NOTE 16 - SEGMENT INFORMATION

The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks, Wolf and

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Matador Resources Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 16 — SEGMENT INFORMATION — Continued

Stateline asset areas and the Greater Stebbins Area in the Delaware Basin, which comprise most of the Company’s midstream operations, are conducted through San Mateo (see Note 6). San Mateo and its subsidiaries are not guarantors of the Notes or the Credit Agreement.

The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.”

			Exploration and Production																		Consolidations and Eliminations						Consolidated Company
									Midstream						Corporate
Year Ended December 31, 2021
Oil and natural gas revenues			$	1,695,032					$	5,510					$	—					$	—					$	1,700,542
Midstream services revenues			—						228,817						—						(153,318)						75,499
Sales of purchased natural gas			47,398						38,636						—						—						86,034
Realized loss on derivatives			(220,105)						—						—						—						(220,105)
Unrealized gain on derivatives			21,011						—						—						—						21,011
Expenses(1)			794,880						142,444						85,899						(153,318)						869,905
Operating income(2)			$	748,456					$	130,519					$	(85,899)					$	—					$	793,076
Total assets(3)			$	3,324,681					$	879,672					$	57,800					$	—					$	4,262,153
Capital expenditures(4)			$	778,191					$	59,361					$	376					$	—					$	837,928

_____________________

(1)Includes depletion, depreciation and amortization expenses of $310.9 million and $31.5 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.6 million.

(2)Includes $55.7 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3)Excludes intercompany receivables and investments in subsidiaries.

(4)Includes $263.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $28.5 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2021, 2020 and 2019

NOTE 16 — SEGMENT INFORMATION — Continued

			Exploration and Production																		Consolidations and Eliminations						Consolidated Company
									Midstream						Corporate
Year Ended December 31, 2020
Oil and natural gas revenues			$	741,092					$	3,369					$	—					$	—					$	744,461
Midstream services revenues			—						166,194						—						(101,262)						64,932
Sales of purchased natural gas			20,736						21,006						—						—						41,742
Lease bonus - mineral acreage			4,062						—						—						—						4,062
Realized gain on derivatives			38,937						—						—						—						38,937
Unrealized loss on derivatives			(32,008)						—						—						—						(32,008)
Expenses(1)			1,334,378						97,599						52,910						(101,262)						1,383,625
Operating (loss) income(2)			$	(561,559)					$	92,970					$	(52,910)					$	—					$	(521,499)
Total assets(3)			$	2,782,819					$	836,509					$	67,952					$	—					$	3,687,280
Capital expenditures(4)			$	518,198					$	201,440					$	2,200					$	—					$	721,838

_____________________

(1)Includes depletion, depreciation and amortization expenses of $335.8 million and $23.3 million for the exploration and production and midstream segments, respectively. Includes full-cost ceiling impairment of $684.7 million for the exploration and production segment. Also includes corporate depletion, depreciation and amortization expenses of $2.7 million.

(2)Includes $39.6 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3)Excludes intercompany receivables and investments in subsidiaries.

(4)Includes $70.5 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $112.1 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

			Exploration and Production																		Consolidations and Eliminations						Consolidated Company
									Midstream						Corporate
Year Ended December 31, 2019
Oil and natural gas revenues			$	886,127					$	6,198					$	—					$	—					$	892,325
Midstream services revenues			—						135,953						—						(76,843)						59,110
Sales of purchased natural gas			4,802						69,967						—						—						74,769
Lease bonus - mineral acreage			1,711						—						—						—						1,711
Realized gain on derivatives			9,482						—						—						—						9,482
Unrealized loss on derivatives			(53,727)						—						—						—						(53,727)
Expenses(1)			621,687						130,612						72,734						(76,843)						748,190
Operating income (loss)(2)			$	226,708					$	81,506					$	(72,734)					$	—					$	235,480
Total assets(3)			$	3,360,725					$	647,937					$	61,014					$	—					$	4,069,676
Capital expenditures(4)			$	718,712					$	223,612					$	3,701					$	—					$	946,025

_____________________

(1)Includes depletion, depreciation and amortization expenses of $331.7 million and $16.1 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.7 million.

(2)Includes $35.2 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3)Excludes intercompany receivables and investments in subsidiaries.

(4)Includes $48.3 million attributable to land and seismic acquisition expenditures related to the exploration and production segment and $145.4 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

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UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2021, 2020 and 2019

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES

Costs Incurred

The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2021, 2020 and 2019 (in thousands).

						Year Ended December 31,
						2021						2020						2019
Property acquisition costs
Proved						$	145,759					$	8,003					$	3,767
Unproved and unevaluated						104,582						61,984						39,595
Exploration costs						51,534						29,370						109,439
Development costs						476,316						418,840						570,290
Total costs incurred(1)						$	778,191					$	518,197					$	723,091

__________________

(1)Excludes midstream-related development and corporate costs of approximately $59.7 million, $203.6 million and $227.3 million for the years ended December 31, 2021, 2020 and 2019, respectively.

Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the year ended December 31, 2021, approximately 58% of the Company’s property acquisition costs resulted from the acquisition of proved properties, while for the years ended December 31, 2020 and 2019, most of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold and mineral interests.

Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to be prospective for oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. For the years ended December 31, 2021, 2020 and 2019, the Company capitalized $7.5 million, zero and $2.9 million, respectively, of geological and geophysical costs, which are included as exploration costs in the table above.

Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities.

Costs incurred also include newly established asset retirement obligations, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were an increase of $1.4 million, a reduction of $0.2 million and an increase of $4.3 million for the years ended December 31, 2021, 2020 and 2019, respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $38.4 million, $30.0 million and $31.1 million of these internal costs for the years ended December 31, 2021, 2020 and 2019, respectively, excluding midstream-related capitalized general and administrative expenses. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $4.8 million, $5.0 million and $7.6 million of its interest expense for the years ended December 31, 2021, 2020 and 2019, respectively, excluding midstream-related capitalized interest expense.

Oil and Natural Gas Reserves

Proved reserves are estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates.

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Matador Resources Company and Subsidiaries

UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED

December 31, 2021, 2020 and 2019

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where

the NGLs are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2021, 2020 and 2019 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period from January through December 2021, these average oil and natural gas prices were $63.04 per Bbl and $3.60 per MMBtu, respectively. For the period from January through December 2020, these average oil and natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively. For the period from January through December 2019, these average oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively.

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Table of Contents

Matador Resources Company and Subsidiaries

UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED

December 31, 2021, 2020 and 2019

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas.

						Net Proved Reserves
						Oil						Natural Gas						Oil Equivalent
						(MBbl)						(MMcf)						(MBOE)
Total at December 31, 2018						123,401						551,474						215,313
Revisions of prior estimates						(605)						34,062						5,073
Net divestitures of minerals-in-place						(298)						(12,048)						(2,307)
Extensions and discoveries						39,477						114,833						58,616
Production						(13,984)						(61,083)						(24,164)
Total at December 31, 2019						147,991						627,238						252,531
Revisions of prior estimates						6,587						19,444						9,828
Net acquisitions of minerals-in-place						11						1,078						190
Extensions and discoveries						21,291						84,043						35,297
Production						(15,931)						(69,501)						(27,514)
Total at December 31, 2020						159,949						662,302						270,332
Revisions of prior estimates						14,346						165,423						41,916
Net acquisitions of minerals-in-place						7,533						11,976						9,529
Extensions and discoveries						17,318						94,532						33,074
Production						(17,840)						(81,686)						(31,454)
Total at December 31, 2021						181,306						852,547						323,397
Proved Developed Reserves
December 31, 2018						53,223						246,229						94,261
December 31, 2019						59,667						276,258						105,710
December 31, 2020						69,647						323,160						123,507
December 31, 2021						102,233						546,173						193,262
Proved Undeveloped Reserves
December 31, 2018						70,178						305,245						121,052
December 31, 2019						88,324						350,980						146,821
December 31, 2020						90,301						339,142						146,825
December 31, 2021						79,073						306,374						130,135

The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2021, 2020 and 2019.

The Company’s proved oil and natural gas reserves increased 20% from 270.3 million BOE at December 31, 2020 to 323.4 million BOE at December 31, 2021. The Company’s proved oil and natural gas reserves increased by 84.5 million BOE and the Company produced 31.5 million BOE during the year ended December 31, 2021, resulting in a net increase of 53.1 million BOE. The Company added 33.1 million BOE in proved reserves through extensions and discoveries during 2021, of which 22.4 million BOE resulted from new well locations drilled during 2021 to establish proved developed reserves and 26.9 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2021, but which were partially offset by the removal of 16.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of our properties in the Delaware Basin. As the Company continues to develop its Delaware Basin assets, the Company may reclassify some or all of this 16.3 million BOE to proved

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Table of Contents

Matador Resources Company and Subsidiaries

UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED

December 31, 2021, 2020 and 2019

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

reserves at a future date. The Company also realized 41.9 million BOE in net upward revisions to prior estimates, 96% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of its properties. The Company also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of its properties. In addition, the Company realized 9.5 million BOE in net upward revisions to its proved oil and natural gas reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021.

The Company’s proved developed oil and natural gas reserves increased 56% from 123.5 million BOE at December 31, 2020 to 193.3 million BOE at December 31, 2021. The Company’s proved developed oil and natural gas reserves increased by 101.2 million BOE and the Company produced 31.5 million BOE during the year ended December 31, 2021, resulting in a net increase of 69.8 million BOE. The Company added 22.4 million BOE in proved developed reserves through extensions and discoveries during 2021, which resulted from new well locations drilled during 2021 to establish proved developed reserves. The Company realized approximately 33.8 million BOE in net upward revisions to prior estimates, 97% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of its producing properties. The Company also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of its producing properties. In addition, the Company converted 40.1 million BOE of its proved undeveloped reserves to proved developed reserves primarily through its development activities in the Delaware Basin during 2021, primarily in the Company’s Stateline asset area, in the Greater Stebbins Area and in the Rodney Robinson leasehold in the Antelope Ridge asset area. In addition, the Company realized 4.9 million BOE in net upward revisions to its proved developed reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021.

The Company’s proved undeveloped oil and natural gas reserves decreased 11% from 146.8 million BOE at December 31, 2020 to 130.1 million BOE at December 31, 2021. The Company added 26.9 million BOE in proved undeveloped reserves through extensions and discoveries during 2021, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2021, but which were partially offset by the removal of 16.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of the properties in the Delaware Basin. The Company realized approximately 8.1 million BOE in net upward revisions to its prior estimates of proved undeveloped reserves, 90% of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2021, which resulted in longer estimated economic lives for certain of its proved undeveloped locations. The Company also had small upward revisions to prior estimates attributable to increased working interests and lower estimated operating costs on certain of its proved undeveloped locations. In addition, the Company realized 4.6 million BOE in net upward revisions to its proved undeveloped reserves at December 31, 2021 as a result of property acquisitions and divestitures completed during 2021. During 2021, the Company also converted 40.1 million BOE of its proved undeveloped reserves to proved developed reserves primarily through its development activities in the Delaware Basin during 2021, as noted above.

At December 31, 2021, the Company’s proved reserves were comprised of 56% oil and 44% natural gas and were approximately 60% proved developed and 40% proved undeveloped. This increase in the Company’s proved developed reserves to 60% of its total proved reserves at December 31, 2021 reflected a significant change in the Company’s percentage of proved developed reserves, as compared to 46% and 42% proved developed reserves at December 31, 2020 and 2019, respectively.

The Company’s proved oil and natural gas reserves increased to 270.3 million BOE at December 31, 2020 from 252.5 million BOE at December 31, 2019. The Company’s proved oil and natural gas reserves increased by 45.3 million BOE and the Company produced 27.5 million BOE during the year ended December 31, 2020, resulting in a net increase of 17.8 million BOE. The Company added 35.3 million BOE in proved reserves through extensions and discoveries during 2020, of which 15.2 million BOE resulted from new well locations drilled during 2020 to establish proved developed reserves and 20.1 million BOE consisted primarily of new proved undeveloped locations identified as a result of drilling activities on its existing acreage in the Delaware Basin during 2020. The Company also realized 9.8 million BOE in net upward revisions to prior estimates at December 31, 2020, which included positive revisions to prior estimates of 31.2 million BOE attributable primarily to revisions to prior forecasts resulting from better-than-expected well performance during 2020, which was offset by negative revisions to prior estimates of 21.4 million BOE primarily resulting from lower weighted oil and natural gas prices used to estimate proved reserves at December 31, 2020, as compared to December 31, 2019. The Company’s proved developed oil and natural gas reserves increased to 123.5 million BOE at December 31, 2020 from 105.7 million BOE at December 31, 2019, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware

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Table of Contents

Matador Resources Company and Subsidiaries

UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED

December 31, 2021, 2020 and 2019

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

Basin. At December 31, 2020, the Company’s proved reserves were made up of approximately 59% oil and 41% natural gas and were approximately 46% proved developed and 56% proved undeveloped.

The Company’s proved oil and natural gas reserves increased to 252.5 million BOE at December 31, 2019 from 215.3 million BOE at December 31, 2018. The Company’s proved oil and natural gas reserves increased by 61.4 million BOE and the Company produced 24.2 million BOE during the year ended December 31, 2019, resulting in a net increase of 37.2 million BOE. The Company’s proved oil and natural gas reserves increased by 58.6 million BOE during 2019 as a result of extensions and discoveries during the year, which were primarily attributable to drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas reserves increased by 5.1 million BOE during 2019 as a result of upward revisions of prior estimates, which were attributable to better-than-expected well performance from certain wells, but which were also partially offset by downward revisions attributable to the lower weighted average oil and natural gas prices used to estimate proved reserves in 2019, as compared to 2018. The Company’s proved oil and natural gas reserves decreased 2.3 million BOE in 2019 as a result of net divestitures of minerals-in-place primarily in the Eagle Ford Shale in South Texas and the Haynesville Shale in Northwest Louisiana. The Company’s proved developed oil and natural gas reserves increased to 105.7 million BOE at December 31, 2019 from 94.3 million BOE at December 31, 2018, primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. At December 31, 2019, the Company’s proved reserves were made up of approximately 59% oil and 41% natural gas and were approximately 42% proved developed and approximately 58% proved undeveloped.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates.

As noted previously, for the period from January through December 2021, the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $63.04 per Bbl and $3.60 per MMBtu, respectively. For the period from January through December 2020, the comparable average oil and natural gas prices were $36.04 per Bbl and $1.99 per MMBtu, respectively. For the period from January through December 2019, the comparable average oil and natural gas prices were $52.19 per Bbl and $2.58 per MMBtu, respectively.

Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and gathering costs, gravity and energy content and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations.

Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows.

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Table of Contents

Matador Resources Company and Subsidiaries

UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED

December 31, 2021, 2020 and 2019

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2021, 2020 and 2019 (in thousands).

						Year Ended December 31,
						2021						2020						2019
Future cash inflows						$	15,174,065					$	6,587,343					$	8,771,595
Future production costs						(4,588,677)						(2,606,956)						(3,087,142)
Future development costs						(1,251,581)						(1,075,317)						(1,638,744)
Future income tax expense						(1,836,009)						(228,848)						(479,011)
Future net cash flows						7,497,798						2,676,222						3,566,698
10% annual discount for estimated timing of cash flows						(3,122,373)						(1,091,823)						(1,532,715)
Standardized measure of discounted future net cash flows						$	4,375,425					$	1,584,399					$	2,033,983

The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2021, 2020 and 2019 (in thousands).

						Year Ended December 31,
						2021						2020						2019
Balance, beginning of period						$	1,584,399					$	2,033,983					$	2,250,613
Net change in sales and transfer prices and in production (lifting) costs related to future production						3,347,910						(1,126,777)						(622,710)
Changes in estimated future development costs						(238,871)						177,074						(284,748)
Sales and transfers of oil and natural gas produced during the period						(1,412,591)						(546,169)						(682,747)
Net purchases (divestitures) of reserves in place						178,695						1,803						(28,849)
Net change due to extensions and discoveries						620,235						296,617						733,208
Net change due to revisions in estimates of reserves quantities						786,061						93,066						63,436
Previously estimated development costs incurred during the period						240,664						253,165						258,593
Accretion of discount						165,799						240,728						237,548
Other						1,737						16						(4,861)
Net change in income taxes						(898,613)						160,893						114,500
Standardized measure of discounted future net cash flows						$	4,375,425					$	1,584,399					$	2,033,983

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